Compendium of ADC
Compendium
of
Advanced Drilling Course
1
Compendium of ADC
Content
1. Well Control
1.1.
1.2.
1.3.
1.4.
1.5.
1.6.
Introduction
Well control equipment
Preparing for Killing
Five safety margins
Killing by means of the Driller’s Method
Gas solubility and its operational effects
2. Casing Design
2.1. Casing Characteristics
2.2. Typical Design of three common Casing Strings
2.2.1. Surface Casing
2.2.2. Intermediate Casing
2.2.3. Production Casing
3. Drillstring Mechanics
3.1. Drillstring Specification
3.2. Stresses in the Drillstring (Drag and Torque)
3.3. Stuck pipe
4. Directional Drilling
4.1. Planning the well
4.3. Directional drilling and necessary equipment
4.2. Estimating the trajectory
4.2.1. Survey Tool
4.2.2. Straight Trajectory
4.2.3. Curved Trajectory
5. Wellbore Stresses
5.1. Surveillance of drilling operations
5.1.1. Surface collected data
5.1.2. Downhole data collection-MWD
5.2. Wellbore instability
5.2.1. Rock mechanics
5.2.2. The Mohr circle and its shear failure envelope
5.2.3. Tensile failure
5.2.4. Summary of all failure types
5.3. LC and countermeasures
5.3.1. Main reason behind LC; narrow pressure window
5.3.2. Three countermeasures to LC
6. Modelling of Drilling Fluid Temperature
6.1. Temperature issues
6.2. Conduction
6.3. Convection
6.4. Composite overall heat transfer
6.5. Effect of high temperature
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Compendium of ADC
7. Completion Methods
7.1. Completion. Fluids
7.2. Well completion
7.2.1. Completion Goal
7.2.1. Completion Operations
7.2.3. Completion Types
7.2.4. Completion Components
7.2.5. Pressure Expansion of Tubing
7.2.6. Well Barriers
7.3. Fracture stimulation
7.4. Acid fracturing and stimulation
7.4. Work over operations
8. Three Downhole problems
8.1. Chemical stability of the wellbore wall
8.1.1. Transport of material through shale
8.1.2. Swelling mechanisms
8.1.3. Inhibitive muds
8.2. Offshore related challenges
8.2.1. SWF
8.2.2. SG
8.2.3. Gas hydrates
8.3. Gas migration through cement
8.3.1. Hydration of cement slurry
8.3.2. Laboratory testing of cement
8.3.3. The GM problem
8.3.4. GM routes
8.3.5. Solution to GM (from SI to OFU)
References
Symbols
3
Compendium of ADC
1. Well Control
1.1. Introduction
Figure 1-1 shows, in general, how to maintain safety against drilling into threatening high pore pressure
zones.
Drilling
operation
Detect high
pressure
Yes
Adjust
mud
weight
no
Kill well
No
Detect kick.
Close well
Find
alternative
ways to handle
this situation
yes
Casing
pressure >
MAASP
Figure 1-1: General procedure to maintain safety during drilling.
There exist a number of different killing methods, while the two main methods are Driller’s and
Engineer’s Method. The Engineer’s Method is also called Wait & Weight Method, abbreviated to
W&W, but the most common method of restoring an overbalanced situation after a kick has occurred is
the Driller’s Method, which is, for ADC, the selected killing method for demonstrating the principles of
killing a well.
Gas is a much more difficult kick fluid to handle than liquids, and from here on, we only discuss gas
kicks. A small volume of gas at the bottom of a well is potentially dangerous because it expands while
approaching the lower hydrostatic pressure on its way to surface. At lower pressure, it will expand
and displace a corresponding amount of mud from the well, thus reducing the bottomhole pressure,
which in turn allows more gas to flow in from the pores. As a pedagogic simplification, the gas law is
assigned with constant temperature and compressibility, yielding:
pV = constant
(1.1)
In more advanced killing methods reality gas behavior is applied. And small influxes of gas are not
likely to be detected with standard kick-detection methods, but as gas expands on its way up the
annulus, it will most likely be noticed in the pits.
Another problem with gas kicks is that gas leads to a decrease of mud rheology, especially in OBM,
and barite may slip out of solution and thus reducing the mud weight locally. Barite must be delivered
from the supply base in adequate amounts to sufficiently increase the mud weight of the total active
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Compendium of ADC
mud volume. A typical active mud volume for offshore operations amounts to 200 m3 in surface tanks,
and additional 200 – 400 m3 inside the well.
1.2. Well control equipment and closing procedure
Blowout preventers and accessory equipment give the driller the capability to:
1.
2.
3.
5.
Close the borehole when high-pressure formation fluids enter it. For onshore drilling the
closing takes place just below the drill floor, for offshore drilling (from a floater) the
closing takes place at the sea floor
Control the release of high-pressure pore fluids and pump weighted mud under high pressure
into the well to restore balanced pressure situations (killing the well)
Move the drill string through a closed BOP while the well is closed and under pressure
(stripping)
Disconnect, cut off and leave the drill string inside the closed well if necessary (last resort)
Figure 1-2 gives an overview of the blowout preventer (BOP) and associated equipment on a floating
drilling rig, together with the mud circulating system.
For offshore drilling at shallow or moderate depths, the drill string and drilling components are guided
to the wellbore location along guidelines extending from a guide frame, previously placed on the ocean
floor. The blowout preventer stack is attached to the guide frame and the 20” casing.
choke manifold
ppump
flare
Degasser
pcsg
pdp
xx x
mud
pits
marine riser
Guide lines
Tool joint
BOP
Pipe ram on which drill
string is hanged off
Guide frame
Degasser
Flare
pcsg
pdp
Maring riser
Guide frame
Guide lines
Separate out gas from returning mud
Burns returning gas
Casing pressure = choke pressure = annular pressure
Drill pipe pressure = stand pipe pressure (SPP)
A connection between well head and the surface on floating rigs
A 300 ton heavy anchor for the wellhead
4 guide lines are fixed to the 4 corners of the guide frame
on which guide tools are run to guide equipment into the wellbore
Influx
Figure 1-2: Kick control on offshore rigs. Surface mud lines in red.
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Compendium of ADC
Figure 1-3 gives an overview of well control equipment (well closing equipment).
Drill string BOP equipment:
Annular BOP equipment:
Choke manifold
Main choke
Mud pump (the piston)
xx x
back to mud pit
Kill line / Choke line
Upper kelly cock
Lower kelly cock
Inside BOP
Stored on drill floor. Flapper valve.
Installed on demand
Faile safe valve
BOP:
Annular
Reinforced rubber elements. Can close around TJ
Pipe ram
Inside BOP
Flapper valve, just above rock bit
Blind/shear ram
Figure 1-3: Well control equipment applied to close the drill string (left box) and annulus (right box).
Standard procedure for closing the well on floating rigs during drilling is (refer to Figure 1-3):
0. A kick alarm is initiated
1. Hoist up drill string at least 4 m. This will hinder fill (of cuttings and weighting material) to
block bit nozzles during killing
2. Stop pump, check for flow. Is it a real kick or a false alarm?
3. First priority-closing elements:
a. Close upper annulus first (allowing to close around TJ. Do not need to know TJ’s
position at this initial stage)
b. Close drill string if not already closed (e.g. by the piston in the mud pump)
c. Open inner and outer fail-safe valve (if not already open, in accordance with
alternative procedure) and slowly close main choke in choke manifold
d. Observe MAASP (avoid fracturing the formation during closing the BOP)
4. Close remaining valves in BOP and hang off drill string by letting a tool joint rest on the
closed ram preventer
a. Check position of the TJ closest to the closing pipe-preventer
b. Adjust position of TJ by hoisting drill string up
c. Close pipe ram preventer
d. Lower drill string carefully and hang it off and let its TJ rest on the closed pipepreventer
5. Read kick volume, shut-in drill pipe pressures (SIDPP) and of casing (SICP)
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Compendium of ADC
1.3. Preparing for killing
We need to consider a few points before circulating out the kick volume.
Stabilized pressure just after shut-in
It is sometimes easier to view the circulating system as a U-tube like in Figure 1-4. The important point
is that the two "tubes", the drill string and the annulus, are connected at the bottom, and here the pressure
is identical. Figure 1-5 shows how the pore pressure affects the pressure in a shut-in, static well (after
pressure has stabilized, which typically takes a few minutes).
Choke valve
Drill string
Choke line
Choke line
Annulus
Drill string
BOP
Well in normal view
Well as U-tube
Figure 1-4: Well in two different views.
SIDPP
SICP
Kill mud
Mud pressure inside
annulus (or casing)
Shut in pressure
inside drill string
Shut in pressure
inside annulus
Historic pore pressure
along the well
Mud pressure
before shut-in
Depth
Gas-kick
entered annulus
Depth of
interest
Pressure
Figure 1-5: Pressure before (left) and after shut-in.
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Compendium of ADC
Gas percolation in a closed well
After closing the well, gas will rise due to buoyancy, but the volume remains constant in accordance
with eqn. 1.1 since the gas is not allowed to expand in a closed well. Therefore, also the pressure of the
gas bubble will remain constant. If the gas kick arrives at the surface (without fracturing the formation
or the equipment), the pore pressure has been “transported” along with the gas bubble to the surface as
shown in Figure 1-6.
SIDPP
SICP
Mu d
Gas percolating
up the annulus
without being
allowed to
expand since the
well is closed
pres
sure
Gas kick in
four different
stages during
percolation
in a
nnu
lus
befo
h
re s
ut in
Pore
Depth
pres
sure
Pressure
Figure 1-6: Pressure development as gas percolates to the surface in a closed well (assuming the formation will
withstand the high pressure).
1.4. Five Safety margins
We present five safety factors related to pressure control in a drilling well.
MAASP: Figure 1-7 demonstrates the importance of the expression called MAASP (maximum
allowable annular surface pressure). If the surface pressure rises above MAASP, the formation below
the casing shoe will fracture.
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Compendium of ADC
SICP
MAASP
c
Fra
e
tur
pre
re
pres
ssu
Mu d
sure
Mud pressure
during LOT (r1)
in a
nnu
lus
befo
Fracture pressure (rfrac)
h
re s
Casing shoe
ut in
(r 2)
Histo
ric
Depth
pore
p
ressu
re
Pressure
Figure 1-7: MAASP.
MAASP can be estimated through eqn. 1.2.
𝑀𝐴𝐴𝑆𝑃 = (𝜌𝑓𝑟𝑎𝑐 − 𝜌2 ) ⋅ ℎ𝑐𝑠𝑔.𝑠ℎ𝑜𝑒 ⋅ 𝑔 = 𝑃𝐿𝑂 − (𝜌2 − 𝜌1 ) ⋅ ℎ𝑐𝑠𝑔.𝑠ℎ𝑜𝑒 ⋅ 𝑔
(1.2)
Here rfrac is the equivalent density that balances the fracture pressure
r1 has been applied earlier during LOT
rfrac is applied (now) while drilling into higher pore pressure
Trip Margin: A safety margin has to be added; typically 0.05 kg/l. It should at least be sufficient to
avoid swabbing during the subsequent tripping operations. An empirical formula sometimes seen is:
𝑃𝑎
Trip margin= 0.01 ⋅ 𝜏𝑦 ⁄{(𝑑𝑏𝑖𝑡 − 𝑑𝑑𝑟𝑖𝑙𝑙 𝑐𝑜𝑙𝑙𝑎𝑟 ) ⋅ 𝑔} = ( 0.01⋅20
= 40 𝑘𝑔/𝑙)
0.05⋅9.81
(1.3)
Kick margin: To protect against fracture an additional margin of typically 0.05 kg/l is subtracted from
the fracture gradient.
Riser margin: A special type of safety margin (SM) for offshore operations is the Riser Margin. When
the location has to be abandoned for some reason, the riser is disconnected at the upper connector in the
BOP, and mud in the riser is automatically replaced by sea water and an air gap.
Kick tolerance: Kick Tolerance is the maximum kick volume, Vinflux, which can be taken into the
wellbore and circulated out without fracturing the formation at the weakest point.
The involved parameters are shown in Figure 1-8. Here the gas kick is shown at time of shut-in as
Vinflux and later, during killing, when it reaches its critical position; the casing shoe, Vcs.
Vinflux = Kick tolerance
(1.4)
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Compendium of ADC
We need to back calculate it from pfrac to Vinflux:
𝜌𝑓𝑟𝑎𝑐 + 𝑔𝑔𝑎𝑠 ∙ 𝑔 𝐻 + 𝜌1 𝑔 (hwell – hcs – H) = ppore
(1.5)
Knowing the capacity of the well and the ppore we find:
ppore  Vinflux = pfrac  Vcs
H = Vcs / Capcs
(1.6)
(1.7)
rmud
rcs
pfrac
Casing shoe
H
hcs
Depth
Vinflux
Pressure
hwell
ppore
Figure 1-8: Parameters involved in estimating kick tolerance
In terms of SIDPP the kick tolerance becomes:
SIDPPmax = (rCS – r1) ⋅hCS⋅g
(1.8)
It is also useful to translate it into mud weight, rkick tolerance. It is the maximum mud density that the
weakest part of the borehole can withstand in the event that a kick is taken. It increases with drilled
depth:
𝜌𝑘𝑖𝑐𝑘 𝑡𝑜𝑙𝑒𝑟𝑎𝑛𝑐𝑒 = 𝜌1 +
ℎ𝐶𝑆
ℎ𝑤𝑒𝑙𝑙
(𝜌𝑓𝑟𝑎𝑐 − 𝜌1 )
(1.9)
In casing string design one of the Load Cases applies Kick Tolerance.
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Compendium of ADC
1.5. Killing by means of Driller’s Method
In the Driller's Method the pore fluid is displaced before kill mud is injected. This row of action
simplifies the operation. However, it requires more time for the entire operation than with the Engineer’s
method.
Annular pressure becomes higher when applying the Driller's Method, compared to applying the
W&W method, and the choke nozzles erode quicker. If there is a risk of fracturing the well at its
weakest point; below the casing shoe, the W & W-method must be chosen. W & W is used in long
openhole sections to reduce the pressure in the annulus; otherwise the Driller's Method is preferred.
In situations when the casing shoe is set deep, the gas bubble will be inside the casing before the kill
mud reaches the bit, and W&W will give no advantages. The Driller's Method is simple, and the total
time it takes is practically the same as for W & W. It is important to get started fast to avoid the pressure
increase due to gas percolation (see next page).
Killing of a well that has to be shut-in because of a kick follows three principles:
1. Bottom pressure must balance the pore pressure plus a small overbalance.
2. Bottom pressure is controlled through the drill string, which is filled with a mud of known
density.
3. After pump is turned on and running with a constant, predetermined rate, bottom pressure is
regulated with a back-pressure valve at the surface.
Six phases of the Driller’s method
Killing by means of the Driller's procedure can best be understood by dividing the operation into six
separate phases. Figure 1-9 presents the complete procedure exemplified through the following kick
situation:
Mud in use:
Depth of well (TVD):
Previously recorded circulation pressure:
Slow Circulation Rate:
Pump capacity:
SIDPP:
SICP:
Kick volume:
Annular capacity around BHA:
Drill string internal capacity:
rmud
= 1 100 kg/m3
D
= 2 000 m
pc1
= 28 bar (SCP)
SCR = 30 SPM
q
= 20 l/stroke
pSIDP = 18 bar
pSIC
= 22 bar
Vkick = 1 m3
CapBHA = 14 l/m
Capdp = 8 l/m
Bottomhole pressure must be kept constant, and pressure in annulus observed closely. 45 or 60 SPM are
common "slow circulation rates", while 30 or 40 SPM are normal on a floating rig, sometimes even 15
SPM is used when the gas is entering the choke line. Too quick expansion makes it difficult to keep
track of the change in pressure.
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Compendium of ADC
Before any kick occurs, it is decided what circulation rate should be used to kill the well. The so-called
SCR is used to determine the friction in the system. We assume, especially for offshore operations, that
this pressure loss occurs in the choke line and the choke.
22
18
46
46
46
18
0
Casing pressure
Pump pressure
pressure
SIDPP + SCP
SCP2
SIDPP
A kick is detected
while drilling and
pump turned off
SICP
SIDPP
Hours or pump strokes
Figure 1-9: A gas kick in six stages handled by means of the Driller’s Method (without including the SM)
Phase 1: The kick has been shut in and we can use the obtained information to estimate the following
parameters: rkill and rkick.
After the close-in action is completed, the pumps seal the well at the drill string side (of the U-tube),
and at the other side by means of closed BOP and surface choke. Inside the drill string, the liquid
composition is assumed to be uncontaminated, so that the new formation pressure becomes:
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Compendium of ADC
𝑝𝑝𝑜𝑟𝑒 = 𝑝𝑆𝐼𝐷𝑃 + 𝜌𝑚𝑢𝑑 ⋅ 𝑔 ⋅ ℎ𝑤𝑒𝑙𝑙 = 𝜌𝑘𝑖𝑙𝑙 ⋅ 𝑔 ⋅ ℎ𝑤𝑒𝑙𝑙
(1.10)
= 18 ⋅ 105 + 1 100 ⋅ 9.81 ⋅ 2 000 = 234 ⋅ 105 = 234 𝑏𝑎𝑟
𝜌𝑘𝑖𝑙𝑙 = 𝜌𝑚𝑢𝑑 +
𝑝𝑆𝐼𝐷𝑃
ℎ𝑤𝑒𝑙𝑙 ⋅𝑔
= 1 100 +
18⋅105
9.81⋅2 000
= 1 192 𝑘𝑔/𝑚3
It is always of importance to check what type of fluid that has entered the well. If only liquid (oil, water
or mud) has entered the well, the displacement procedure is simplified and will, by far, not be as critical
as for a gas kick. However, the killing procedure will still be the same.
Volume gained in the pit, Vkick, represents the quantity of the formation fluid entering the well bore. The
length of the annulus occupied by the unknown fluid, which is estimated in Eqn. 1.11, and the difference
between shut-in pressures; pSIC and pSIDP, determines its gradient. The height of the fluid is determined
from the volumetric capacity, Cam, at the bottom part of the well:
ℎ𝑘𝑖𝑐𝑘 =
𝑉𝑘𝑖𝑐𝑘
𝐶𝑎𝑛𝑛
(1.11)
Previous figure showed that the bottomhole pressure can be calculated from two fluid columns; the
annulus column and the drill string column.
𝑝𝑆𝐼𝐷𝑃 + 𝑔 ⋅ 𝜌𝑚𝑢𝑑 ⋅ ℎ𝑤𝑒𝑙𝑙 = 𝑝𝑆𝐼𝐶 + 𝜌𝑚𝑢𝑑 ⋅ 𝑔 ⋅ (ℎ𝑤𝑒𝑙𝑙 − ℎ𝑘𝑖𝑐𝑘 ) + 𝜌𝑘𝑖𝑐𝑘 ⋅ 𝑔 ⋅ ℎ𝑘𝑖𝑐𝑘
(1.12)
Assuming the capacity is constant, we can find hkick and then solving for rkick yields:
h kick = Vkick / Cap BHA = 1 000 l / 14 l/m = 71 m
𝜌𝑘𝑖𝑐𝑘 =
ℎ𝑘𝑖𝑐𝑘 ⋅𝑔⋅𝜌𝑚𝑢𝑑 −(𝑝𝑆𝐼𝐶 −𝑝𝑆𝐼𝐷𝑃 )
ℎ𝑘𝑖𝑐𝑘 ⋅𝑔
=
71 ⋅9.81 ⋅1100−(22−18)⋅105
9.81 ⋅71
= 526 𝑘𝑔/𝑚3
Phase 2: Start the pump. Pump start-up procedure is difficult; well pressure may easily go below the
pore pressure, causing new, small influxes: Open the choke slowly and increase the flow rate slowly and
steadily, i.e. over a period of 15 s, until pump has reached the reduced, predetermined pump speed.
Regulate the choke so that the initial circulation pressure (ICF) at the stand pipe (SPP) becomes:
𝐼𝐶𝑃 = 𝑆𝑃𝑃 = 𝑝𝑑𝑝 = 𝑝𝑆𝐼𝐷𝑃 + 𝑝𝐶1 (+ safety margin) = ICP
(1.13)
The slow circulating rate (SCR) while killing the well (usually one-half of normal pump rate or less)
induces very small pressure drops in the annulus. The slow circulation pressure (SCP or pC1) is mostly
lost in the drill pipe, drill collar and bit nozzles, and may be disregarded in the annulus. This neglection
results in an extra safety factor against the pore pressure, equal to the annulus pressure drop.
Phase 3 and 4: Circulation out the gas: In the other end of the circulation system, the choke pressure,
pchoke, should initially be equal to 𝜃 (+ safety margin) and thereafter slowly increasing due to gas
expansion, reaching a peak value just before gas surfaces, and then quickly dropping to a value equal to
pSIDP. Figure 4 presents a graph of the choke opening:
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Compendium of ADC
Phase 5: Filling drill pipe with heavy mud: In the last moment of phase 5 the heavy mud has reached
the bit. The original pSIDP is now reduced to zero and the friction pressure, pC1, has increased to pc2, due
to the higher resistance of the heavier mud, which also is the Final Circulating Pressure:
𝑝𝐶2 =
𝜌𝑘𝑖𝑙𝑙
𝜌1
⋅ 𝑝𝐶1 = FCP
(1.14)
The reduction of pSIDP and the increase of pC1 is assumed to be a linear change (although it in reality is
not) and are completed when DP is filled with kill mud. We want to know how long it takes:
Volume of drill string:
Strokes to bit:
Time to bit:
2000 m * 8 l/m
16 000 l / 20 l/stroke
800 strokes / 30 strokes /min
= 16 000 l
= 800 strokes
= 27 min
When this pDP-schedule is held, the pressure exerted at the bottom of the well will never be less than
ppore + SM + annular pressure loss, and no further influx of formation fluid will take place. Observe that
the casing pressure during phase 5 is constant.
Phase 6: Filling the annulus with heavy mud:
The DP has now been filled with a mud of known weight, and if the pump speed is held constant, the
pressure loss (pC2) will not be altered from this point on. If pDP (stand pipe pressure or pump pressure)
is kept equal to pC2 + SM by means of the choke, the pressure will now be under control, both in the
drill pipe and the annulus.
Offshore killing operations take typically one day.
Engineer’s Method
The Engineer’s Method is always the first optional method. An extra safety factor is added through this
method because the annular pressure will become lower compared to the Driller's Method. In the
Engineer's Method kill mud circulation is initiated as soon as possible, reducing the drill pipe or pump
pressure as soon as heavy mud enters the annulus, as illustrated in Figure 1-10.
px
Gas (h2)
Casing shoe
Depth
Original mud (h4)
Kill mud
Pressure
Figure 1-10: Comparing critical annular pressure for Driller’s and Engineer’s Method.
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Compendium of ADC
The procedure is much quicker, and the annular pressure will be lower, but all the control functions are
similar to those in the Driller's Method.
The complete killing procedure is always administered through a kill sheet. Figure 1-11 presents a
typical example of a kill sheet. Through a kill sheet the user obtains a complete overview of pressure at
any time. Most of the necessary data are known ahead of time and entered the sheet. The slow circulation
pressure, pc1, changes whenever any of the contributing parameters change, and must be recorded at
least once a day.
The Engineer's Method differs from the Driller's method by the simple fact that the mud weight is being
increased and pumped into the well immediately, instead of first just circulating out the kick fluid.
(SCP 1)
SI
ORIGINAL MUD WEIGHT:
WELL
DEPTH
SCP
KILL SHEET
Well
MD
(SCP )
2
UP CHOKE
LINE
CHOKEL.
FRICTION
SPM
BookBoone
TVD
UP RISER
PUMP
NO 1
: .............................................
SPM
SPM
Comment : .............................................
SPM
PUMP
NO 2
CASING DEPTH
LEAK OFF TEST EQ
SHUT IN DRILLPIPE PRESSURE
(SIDPP)
MAASP
INITIAL DRILLPIPE CIRC. PRESSURE
SHUT IN CASING PRESSURE
ICP = SCP + SIDPP = ........................+.........................
(SICP)
PUMP
OUTPUT
KILL MUD WEIGHT
PIT VOLUME INCREASE
PUMP 1
r
kill =
PUMP 2
r m + SIDPP
9,81 * TVD
FINAL DRILLPIPE CIRC. PRESSURE
FCP = SCP *
CAPACITY
RKB
.......
LENGTH
DP
DC
VOLUME
X
=
X
=
SPM
SPM
r kill
rm
DRILLPIPEPRESSURE
STROKES
TOTAL DRILLSTRING VOL.
STANPIPE
PRESSURE
0
CAPACITY
........
..................
LENGTH
DC/OH
VOLUME
=
X
DC/OH
X
=
DP/CSG
X
=
CHOKELINE
X
=
TOTAL ANNULAR VOL.
.................
VOLUME
SURFACE TO BIT
PUMP OUTPOUT
/
-
BIT TO SHOE
/
-
SHOE TO SURFACE
/
-
TOTAL STROKES
STROKES
STROKES
-
Figure 1-11: An example of a simple Kill sheet. Dark green boxes indicate information known before a kick.
They must be updated at least every shift (every 12 hours). Light red boxes represent information known after
shut-in.
1.6. Gas solubility and its effect on the operation
Solubility in general
Substances dissolved in a solvent are called solutes, which can be solids, liquids or gases. If two liquids
are soluble, they are said to be miscible. Water is a good solvent due to its polar orientation. Ionic
compounds are highly soluble in water; the attractive forces between oppositely charged ions are causing
15
Compendium of ADC
individual ions to separate from its lattice. After dissolution, each dissolved ion becomes surrounded by a
shell of water molecules. The ions are said to be wetted or hydrated. Figure 1-12 shows hydration of
dissolved sodium chloride ions in water.
-
+
-
-
-
-
+
+
+
+
-
+
Na+
+
-
- -
- +
-
-
-
Cl
+
+
+
=
+
+
+
+ +
- +
- -
O
D+
-
D+
H
D-
Strong attraction. Several
layers of water molecules
+
H
Weak attraction. No permanent
structure of water molecules
+
Water molecules are weak dipoles
Figure 1-12: Hydration of sodium chloride in water. In still-standing water many layers of water molecules will
form around the ions.
Ionic compounds are not soluble in non-polar liquids, such as oil. The internal attraction between
multivalent ions (number of valences > 1) like CaCl2 and CaCO3 are much stronger than between univalent
ions. Covalent compounds are soluble or miscible if they are polar. Examples of soluble covalent
compounds include sugar, alcohol and starch.
Gas solubility in brine / gas solubility in pure water
Polar water molecules attached to dissolved salt ions reduce the number of free water molecules (water
activity is being reduced). One effect of reducing the number of free water molecules is seen as the water’s
ability to dissolve gas. It is reducing dramatically as shown in Figure 1-13.
Dissolved salt (%)
Figure 1-13: Gas solubility vs. salt content (Petrucci (1989)).
Solubility of gas in liquids
Temperature: The solubility of gases will slightly increase with increased temperature as indicated in
Figure 1-13.
Pressure: Pressure generally affects the solubility of gas in liquid more than temperature, and, as noted in
Figure 1-14, the effect is always the same: The solubility of gas increases with increasing gas pressure.
16
Compendium of ADC
pgas
xgas
Figure 1-14: Effect of pressure of the solubility of a gas. The solubility of gas molecules in the liquid solvent
increases with increased pressure - the color become lighter (free after Petrucci (1989)).
Gas concentration, xgas, in terms of the mol fraction of gas dissolved in liquids [atm/(atm/mol fraction)]
is proportional to the gas pressure, pgas, above the solution. The proportionality strength is taken care by
Henrys constant H:
𝑥𝑔𝑎𝑠 = 𝑃𝑔𝑎𝑠 ⁄𝐻
[molgas / molliq]
(1.15)
If the need to quantify the solubility arises, mol fraction must be translated to mass of gas, mgas:
𝑀𝑔𝑎𝑠
𝑚𝑔𝑎𝑠 = 𝑥𝑔𝑎𝑠 ⋅ 𝑀
𝑙𝑖𝑞𝑢𝑖𝑑
[ggas / gliq]
(1.16)
Equilibrium is reached between the gas above and the dissolved gas within a liquid when the rates of
evaporating molecules and rate of condensation of the gas molecules become equal.
Operational problems related to dissolved gas
Behavior of
gas in WBM
5
ol
ss
In voir
er
s
re
0.5
Di
ga
s
in
50
Fr
ee
Volume og gas (m )
500
re
se
rv
ve
oi
Li
r
be d g
a
ra
s
tio in
n
o f mu d
M
ga
os
s
tg
st
ar
as
ts
lib
er
at
e
Fr
d
ee
ga
s
A small gas kick, taken in OBM produces a relative small initial increase in annulus pressure and in pit
level as the kick is being circulated to the surface, because dissolved gas behaves like liquids. Gas will
later come out of solution as gas pressure decreases while the kick is being circulated up the annulus.
The gas dissolved in OBM is then released in large volumes as the mud reaches shallow depths as
indicated in Figure 1-15. Unfortunately, these phenomena can lead to inappropriate decisions since the
behavior is quite different from kicks in WBM.
At
bo
At
tto
m
Distance travelled
su
rfa
c
e
Figure 1-15: Volumetric behavior of methane swabbed in during connections while tripping out, dissolved in
OBM and later circulated out, un-detected until liberation as mud reaches shallow depths.
Dissolved gas is related to the volume of gas at standard condition pr. volume of liquid solvent, the gasliquid ratio, Rs (s refers to standard conditions). When oil is the solvent, it is referred to as gas oil ratio
(GOR). Figure 9-20 exemplifies the GOR of methane.
To account for the situation described in Figure 1-16, Rs must first be calculated at the bit depth:
𝑅𝑠 = 𝑞𝑔𝑎𝑠 ⁄𝑞𝑚𝑢𝑑
(1.17)
17
Compendium of ADC
If 𝑅𝑠,𝑏𝑖𝑡 ≤ 𝑅𝑠.𝑠𝑎𝑡𝑢𝑟𝑎𝑡𝑒𝑑 then all the formation gas is dissolved in the mud and the free gas volume
fraction is zero. If, on the other hand, a large enough amount of gas enters the wellbore, so that the
value of Rs,bit exceeds 𝑅𝑠,𝑠𝑎𝑡𝑢𝑟𝑎𝑡𝑒𝑑 , then the mud becomes saturated with gas and any excess appears as
free gas.
Rs (sm3/m3)
Rs, saturated
100
Free gas +
saturated
liquid
50
Dissolved
gas, under
saturated
p (bar)
0
0
100
200
300
Figure 1-16: Rs for CH4 in Mentor oil vs. well pressure at 100 0C, translated to SI-units.
We want to demonstrate the important effects of gas kicks in OBM. Assume the following situation:
A small gas kick enters the well:
Well depth:
Influx period
Mud pump rate:
Mud density:
Mud temperature:
1 m3
2 000 m
3 minutes
2 000 l/min
1.5 kg/l
100 0C
Question: Will the gas dissolve or be “free” at time of influx?
Bottom pressure:
1500 ∙ 9.81 ∙ 2000
= 294 * 105 Pa
3
Mud volume pumped: 2 m /min ∙ 3 min
= 6 m3
Gas ratio at standard conditions: Rs=Vgas/Vmud = (1m3∙294 bar /1 bar) /6 m3 = 49 Sm3 / m3
From Figure 1-16, we see that all the gas will be dissolved.
Question: When will the oil be saturated and gas begins to liberate?
a) At the moment of influx the pressure and oil require Rs to be 100 to be fully saturated,
i.e. twice as high as 49, i.e. the kick volume needed to be 2 m3.
b) Or, alternatively, the 1m3 gas kick with Rs of 49 passes the pressure corresponding to
point of full saturation at 170 bar. For the given mud density this corresponds to a depth
of around 1 140 mTVD.
18
Compendium of ADC
2. Casing Design
2.1. Casing characteristics
The most important performance properties of casing include its rated resistance of axial tension, burst
pressure, and collapse pressure. Axial tension loading results primarily from the weight of the casing
string itself, suspended below the point of interest. Body yield strength is the tensile force required to
cause the pipe body to exceed its elastic limit. Similarly, burst strength is the minimum internal
pressure that will cause the casing to rupture in the absence of protective external pressure and axial
tensile loading. Collapse pressure rating is the minimum external pressure that will cause the casing to
collapse in the absence of protective internal pressure and axial compressional loading. Other
characteristics like geometry, are presented in the lecture notes and in the Data Book.
API has adopted a casing grade designation to define the strength characteristics of the pipe body. The
grade code consists of a letter followed by a number. The letter designation in the API-grade code was
selected arbitrarily to provide a unique designation for each grade of casing, now adopted as the API
standards. The number designates the minimum yield strength of the steel in thousands of psi. Based
on considerable test data, the minimum yield strength should be computed as 80% of the average yield
strength observed. API - casing grades are (with yield strength in ‘psi’) equals to the grade number *
1000). Nine standard grades are available: H-40, J-55, K-55, C-75, L-80, N-80, C-90, C-95 and finally
P-110.
As an introduction to the upcoming discussion further down, Figure 2-1 indicates how a casing is
designed. It also indicates that the complete casing string can be composed of multiple sections with
different steel grade, wall thickness, and coupling types. A “Combination String”, as opposed to a
single grade steel, is the most economical solution. E.g. at the bottom of the well the tensile load is
negligible, and an inexpensive steel grade is sufficient, while at the surface the tensile load is
maximum.
2.2. Typical design of three common casing strings
Load vary with depth. The quality and strength of casings are related to load, and likewise the cost of
casing; the larger the load the higher the quality, and, the higher the costs. Since casings are expensive,
every operator will therefore seek the most economical design; high quality in the bottom and at the
surface, lower quality in the middle. A casing string will thus be designed with several different
qualities and weights, a Combinaiton String.
In the paragraphs to follow we have summarized the information given in the SPE textbook Applied
Drilling Engineering. It will increase your understanding and insight of casing design if you study the
relevant pages in ADE in parallell to, or better, ahead of the classroom teaching. Let it also be clear
that the examplified Load Cases differs between operators.
19
Compendium of ADC
Figure 2-1: Design of casing string with respect to tension. As indicated, the quality of the casing differs vs.
depth. A string composed of more than one specific casing quality is termed a Combination String.
2.2.1. Surface casing (20”)
For the surface casing the load situation is presented in Figure 2-2. It can be summarized through the
following worst-case senarios:
Burst load – is represented by a well control condition; A large kick (with closed BOP) is in the
process of being circulated out, then closed in.
•
•
All mud in the casing is kicked out, replaced by formation gas
Outside pressure is defined by normal pore pressure for that area (cement is degraded
and permeable
Collapse load – is represented by the most severe lost-circulation situation
•
•
•
LC leads to lowering of mud level inside the cemented casing, but the beneficial effect
of drilling fluid dropping only until the BHP = pore pressure at loss zone
Max possible external pressure is defined by the mud applied previously while RIH
with casing (beneficial effect of cement is ignored)
Detrimental effect of axial tension is considered (combined load)
20
Compendium of ADC
Axial tension – The casing is stuck close to bottom (we simplify and assume at the very bottom)
•
•
•
Axial load after cementing is difficult to establish. Assume therefore it to be equal to
its own weight buoyed by hydrostatic pressure existing at the time when max collapse
pressure was encountered
A small amount of pull force is required to pull casing free; Fpull
Combination string is designed. With differential wall thickness, buoyancy is most
accurately estimated by use of the pressure-area method
MUD
Figure 2-2: Load cases of surface casing.
We want to take you through 4 stages of casing design, starting with a depth-pressure graph, ending up
with the design of the surface casing.
Stage 1 - Original pressure situation: In Figure 2-3 we the original pressure situation, before kick
and losses occur.
Surface BOP
P
Sea bed
Conductor
Pore pressure
Drilling fluid pressure
Fracture pressure
Overburden pressure
Surface
casing
DEPTH
Loss Zone
P
Figure 2-3: Original depth–pressure situation for surface casing after drilling next well section.
21
Compendium of ADC
Stage 2 - Load Case: With basic information from stage 1 we are redy to present the load case. This
is shown in Figure 2-4.
0
Surface BOP
P
P
COLLAPSE
BURST
Sea bed
hsee
hmud
Gas inside csg
Mud pressure outside csg while RIH (r1)
Conductor
Pore pressure
outside csg
hcs
Surface
casing
Mud pressure inside casing
while drilling at bottom
and loosing mud (r2)
Mud
P
DEPTH
DEPTH
hLC
Pfrac
hBH
Ppore
P
Figure 2-4: Load situation for Surface Casings. Burst (left) and collapse (right).
Now follows a summary of how to estimate load for three load types; burst, collapse and tension, all in
agreement with the load cases above and as presented in Figure 2-4. The subs o, i, BH, cs, and surf
denotes; outside, inside (of casing), Bottom Hole, casing shoe, and surface, respectively.
Burst
Pi, cs =
Pi,surf =
Po,cs =
Po,surf =
Pfr,cs
Pi,cs – rgas . g . hcs
rpore . g . hcs

Collapse
Fluid level falls until PBH = Ppore,BH = r2 . g . (hLC - hmud) →we can find hmud
Pi,cs = r1 . g . (hcs - hmud)
Po,cs = Pmud while RIH = r1 . g . hcs
Po,surf = Pi,surf = 
Tension
W=
BF =
wcs . hcs . BF + Fpull
1 – rmud / rsteel
As indicated earlier, it is recommended to estimate buoyancy in accordance to exposed areas, and not
like in the line above which gives only an average value.
Stage 3 - Load Line → Combined String: The next step is to find the load-line for surface casings.
Surface casings are shallow, and the axial tension is therefore not critical, but we need it in order to
correct the collapse pressure (combined stress). The load line equals the difference between the outer
22
Compendium of ADC
and the inner pressure in the casing, multiplied by the safety margin (SM). The strength data of burst
and collapse are given in psi or in Pa. We are now ready to compare the load-line with casing
strengths. Figure 2-5 represents this process, including the resulting design.
P
BURST
BURST
P
COLLAPS
N80
COLLAPSE
COMBINED
N80
H40
(Po – Pi) * SM
(Pi – Po) * SM
C75
C75
Po - Pi
Pi - Po
K55
K55
K55
C75
C75
N80
K55
P
H40
C75
N80
K55
H40
P
C75
Figure 2-5. Load-line (including SM) for burst (left) and collapse (middle). Corresponding grades (strengths)
are marked as well. The combined design, the most economic one, is shown to the right.
Stage 4 – Combined Load: Now we have produced first version of surface casing design, and we are
ready to adjust for combined load. To do so we retrieve the graph of combined collapse and tensile
load and presented in Figure 2-6. By combining collapse and axial tension, collapse resistance
becomes lower, and casing design will have to be adjusted.
→ FT (%)
Figure 2-6: Effect of axial tension on collapse strength.
The axial tensile load factor, FT , gives axial load in % of maximum allowable tensile strength; y, of
the strongest casing element (the upper one).
23
Compendium of ADC
FT = Tensile Load / body tensile yield strength = Wcsg / y
Wcsg can be estimated when grades and lengths are known.
Wcsg = wN80 . LN80 + wC75 . LC75 + wK55 . LK55
C75
N80
K55
H40
By taking FT to be, e.g. 0.55, for illustrative purposes, at the surface, where the tension is maximum,
we can read from Figure 2-6 that the Collapse Strengthening Factor equals 0.6. At the bottom of the
casing string the tension is zero, and the Collapse Strengthening Factor is here 1.0. With this
information, Figure 2-7 combines the new strengths with existing load-line.
* 0.6
P
COLLAPS 0
COLLAPS 1
COLLAPSE
COMBINED 1
COMBINED 0
BURST
N80
N80
N80
H40
H40
C75
K55
C75
C75
K55
K55
C75
N80
C75
K55
H40
C75
C75
K55
P
Figure 2-7: Combined load-design after 1. iterative step. Collapse strength has changed from initial design
step (Collapse 0) to Collapse 1, leading to adjusted design; Combined 1. Burst is here assumed unaffected by
tension. We now observe that we need a slightly stronger casing to compensate for the reduced collapse
resistance caused by simultaneous tension.
It results in a new, slightly adjusted design, with adjusted lengths and grades. With new depth of the
individual grade-weight casings, an iterative procedure is necessary to find the adjusted axial tension
vs. new depths. The iteration process continues until the axial load factor stabilizes.
2.2.2. Intermediate casing (13 3/8”)
Design of intermediate casing follows similar procedure as for surface casing; to reach final depth
safely. More critical than for surface casing is now the burst load. The situation is also here based on
underground blowout, just below the casing shoe, while drilling deeper, and a gas kick is circulated
out (with closed BOP), as illustrated in Figure 2-8.
24
Compendium of ADC
Figure 2-8: Burst load for intermediate casing.
The reason for the higher pressure is a combination of larger depth and relatively higher pore pressure
as illustrated in Figure 2-9.
Surface BOP
P
Sea bed
Conductor
Pore pressure
Drilling fluid pressure (r2)
Fracture pressure
Surface
casing
Intermed.
csg
P
Figure 2-9: Initial depth–pressure situation for intermediate casing while drilling next well section.
Since, for the intermediate casing, especially the burst is critical, details of the load case are:
Burst: Max surface internal casing pressure is limited to the rated BOP pressure (typically 10 or
15 000 psi for offshore operations):
•
Drilling fluid (r2) is still inside the casing (assume 50 % emptied by escaping gas from
underground blow out)
25
Compendium of ADC
•
•
•
Max pressure at lost-circulation zone = Pfrac, referred to as Pinjection, plus a safety margin due to
pressure drop within the fracture, DPfrac
Gas density varies with depth (actually with pressure) and can be estimated by the operator
Here we simplify by assuming it to be constant equal to 0.3 kg/l
MW is defined by pore pressure at next casing depth (r2)
Collapse load is like the surface casing’s: If a severe LC zone is encountered near the bottom of the
next interval, and no other permeable formations are present above the LC zone, the fluid level in the
well MAY fall until BHP = Ppore of the LC zone, i.e. to the level called hmud.
For intermediate and for production casing the depths are large and the tensile is therefore critical.
Surface BOP
P
Sea bed
Gas inside casing,
stabilized after shut-in
Sea bed
Pore pressure
outside casing (r1)
Conductor
Surface BOP
P
hmud
Conductor
Mud inside csg (r2)
Mud pressure in-side
csg defined by shoe
frac P, supported by
deepest pore P
Surface
casing
Pfrac + DPfrac
Intermed.
csg
hBH
Surface
casing
Mud pressure
outside csg (r1)
Intermed.
csg
Shut-in gas will maintain pore P through
percolating gas
P
P
Figure 2-10: Load situation for intermediate Casings. Burst (left) and of collapse (right). We observe
that collapse load is often negligible for the intermediate casing.
Estimation of the load details follows the same principles as for surface casing, and the resulting loadline for intermediate casing will be constructed similarly. The first design step is obtained by
computing the load-lines and compare them with the available casing grades (strengths).
The final design includes the iterative process related to combined load.
2.2.3. Production casing (7 “)
The production casing is set at final depth of the well. The pressure-depth situation at this depth is
already presented in Figure 2-9. The loads situation of production casings is illustrated in Figure 2-11,
and specified in more details below.
26
Compendium of ADC
Figure 2-11: Burst (left) and collapse load for production casings
Burst load:
•
•
•
Initial shut-in BHP = Ppore, and gas is produced: For simplification assume rgas = 0.3 kg/l
The tubing may fail (leak) at any depth; Pi = Ptubing
Completion fluid density (MW) is left outside casing
Collapse:
•
•
Late in the reservoir’s life the reservoir pressure is depleted down to normal water pressure
Leak in tubing causes loss of completion fluid. Casing is considered empty!
Axial tensile load:
•
•
Assume no axial support except for buoyancy
Assume a minimum pull force of 50 ton or approximately 50 kdaN
The further casing design process is identical with the already presented designs of casings above, and
design is therefore reserved for your future.
Data Book contains a full example of load cases for all three casing sizes.
3. Drillstring mechanics
27
Compendium of ADC
3.1. Drillstring Specification
For sub-chapter 3.1. we refer you to the lectures and to the Data Book.
3.2. Stresses in the drillstring
First we present the drag model for a straight borehole, illustrated in Figure 3-1.
F2
b
FN
W
F1
Ff
Figure 3-1: Drag conditions for a drillstring element in a straight borehole. Inclination angle should be b.
𝐹2 = 𝐹1 + 𝑤 ⋅ (𝑐𝑜𝑠 𝛽 +/−𝜇 ⋅ 𝑠𝑖𝑛 𝛽)
(3.1)
The plus/minus sign is valid while pulling / lowering the string.
Conditions for sliding we have when downward force equals resisting force. In this manner we can
determine the angle of repose, or angle of sliding, bs;
cos bs =  . sin bs
bs = 1/ . tan-1 bs
(3.2)
Sliding of the drillstring will take place, according to eqn. 3.2, if the well inclination is lower than
what is shown in the list below:

0.15
0.20
b
84.4
78.7
For a curved borehole the model will have to include the effect of bending. Force in a curved borehole
are presented in Figure 3.2. The momentum or bending torque has also two components; local bending
caused by a curved wellbore with radius of curvature equal R, and, existing momentum in lower end
of the element, M1;
M2 = M1 +  . w . R . sin b
()
28
Compendium of ADC
F2
a2 2
R
M2
FN
w
F f = 2 . FN
M1
1
a1
F2
Figure 3-2: Forces acting on a string element in a curved wellbore. Normal force, FN, is also called side force.
Incl. = b.
Analytical model
First, we present an analytical model, consisting of change of weight, mechanical friction and bending
stress along a small string element;
𝑑𝐹 = [−𝜇 ⋅ 𝐹 + 𝑤 ⋅ 𝑅(𝑠𝑖𝑛 𝛽 + 𝑐𝑜𝑠 𝛽)] ⋅ 𝑑𝛽
(3.4)
Along an infinitesimal element we may assume w = 0. Eqn. 3.4 then reduces to:
𝑑𝐹 = −𝜇 ⋅ 𝐹 ⋅ 𝑑𝛽
(3.5)
Rearanging;
𝑑𝐹
𝐹
= −𝜇 ⋅ 𝑑𝛽
(3.6)
Integrating along the complete angular change and including the initial stress F1 at the start of the
angular change, yields;
𝐹 𝑑𝐹
1 𝐹
∫𝐹 2
𝛽
= − ∫𝛽 2 𝜇 ⋅ 𝑑𝛽
1
(3.7)
resulting in this solution;
[𝑙𝑛𝐹2 −𝑙𝑛𝐹1 ] = −𝜇[𝛽2 − 𝜃𝛽1 ]
(3.8)
Changes in azimuth, a, are likewise added as (a2 – a1) to eqn. 3.6. By raising to the power of e on
both sides simplifies the solution;
𝑙𝑛𝐹2
𝐹
𝑒 𝑙𝑛𝐹1 = 𝐹2 = 𝑒 −𝜇(𝛽2 −𝛽1 )
1
(3.9)
29
Compendium of ADC
Rearranging we obtain the answer in radians or in angular degrees;
𝐹2 = 𝐹1 ⋅ 𝑒 −𝜇(𝛽2 −𝛽1 ) = 𝐹1 ⋅ 𝑒 −𝜇⋅
2⋅𝜋⋅(𝛽2 −𝛽1 )
360
(3.10)
Figure 3-3 shows examples of eqn. 3.10.
2 = 90
 = 0.2
F2
1 = 0
F1
D
45
90
180
F2 / F1
1.17
1.37
1.87
Figure 3-3: Exemplifying the analytical model.
Discrete model
For smooth curved hole-sections, the analytical model can be used. However, borehole trajectories are
normally not smooth (inconsistent changes in inclination and azimuth), and therefore a discrete model
is better serving the need. We include changes both in azimuthal and vertical direction.
Axial force
𝐹2 = 𝐹1 + 𝑤 ⋅ 𝑐𝑜𝑠 𝛽 +/−𝜇 ⋅ 𝐹𝑁
(3.11)
Local bending momentum, also called bending torque
𝑀2 = 𝑀1 + 𝜇 ⋅ 𝑟 ⋅ |𝐹𝑁 |
(3.12)
The side force (or normal force) are composed of two sides in right angel tripod;
FN = √(𝐹1 ⋅ 𝛥𝛼 ⋅ 𝑠𝑖𝑛 𝛽)2 + (𝑤 ⋅ 𝑠𝑖𝑛 𝛽 + 𝐹1 𝛥𝛽)2
(3.13)
A negative value means that the normal force FN is reduced since F will tend to lift the drillstring off
the low side of the well in the build-up section. When FN = 0 the string does not touch the walls; the
string behaves like a catenary chain. The friction factor f represents the average condition of the
contact area between two observation points.
The side force has now four sources; its own weight, the existing force at the lower end, axial friction
force, and added force through the curvature, due to bending.
The calculation starts at the bottom and proceeds stepwise upward. Each short element contributes to
small increments of axial load. Since the 3D curvature is decomposed into two perpendicular planes,
the normal force is the vector sum of these two components. The vertical component has two
elements; the weight and the tension.
FN = [(Ft . Da . sin β)2 +/- (Ft . D + w . sin β)2]0.5
(3.15)
30
Compendium of ADC
Tension increment now becomes + for POOH and – for RIH:
DFt = w . cos β +   FN
(3.16)
Bending increment:
DM =   FN  R
(3.17)
When drillstring elements are small, e.g. 100 ft, the error caused by assuming that tension, F1, does not
change over the length of the element, is neglectable. Estimated bending momentum along the bend,
translate to peripherical stress and add to existing axial tension.
3.3. Stuck pipe
Stuck pipe has been the failure type that has caused oil companies the most in terms of lost nonproductive time (NPT). With the introduction of Top Drive, the failure rate decreased, especially with
respect to differential stuck pipe, since the string can be kept rotating while tripping.
The two types of stuck, mechanical and differential, have different causes. Differential stuck pipe is
caused by high difference between wellbore pressure and the pore pressure. This pressure difference is
enabled by a pressure tight filter cake. Mechanical stuck pipe is caused by mechanical restrictions in
the wellbore. Whenever the resistance of moving the drill string axially becomes too large (DHKL >
15 – 20 tons), it might be necessary to stop and clean (ream) the hole, if possible in accordance with
Best Practice. Neglecting to do so may make the situation worse, including failures like stuck pipe.
Downhole restriction can have several causes.
1. Wellbore restrictions
a. Accumulated cuttings and cavings
b. Blocks. Blocks are large, irregular pieces of rock fragments originating either
from the wellbore or its wall or from cement. The wall may be chemically
unstable, surpassing the collapse pressure or be mechanically disturbed by the
drillstring
2. Wellbore wall restriction
a. Swelling shale
b. Creeping fm
c. Key seat
Details on these matters are presented in the lectures. Please show up there. Take good notes. Ask
questions. Why not.
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4. Directional drilling
There are many reasons for drilling directional wells, including:
•
•
•
•
•
•
Side-tracking existing wells (because of hole problems or fish or reaching new targets)
Restricted surface locations
To reduce number of offshore platforms
To reach thin reservoirs (using horizontal or multilateral drilling)
Salt dome drilling (direct the well away from the salt dome to avoid casing collapse)
To avoid gas or water coning problems
Before the actual drilling takes place, the trajectory must be planned.
4.1. Planning the trajectory
Which trajectory to be chosen depends on factors like; how many main targets and which geology
could secure an economical project. The surface location is known. Given the location of the target, it
is possible to calculate the best trajectory. The well profile is projected in the vertical plane as shown
in Figure 4-1. This figure also describes the various sections and parameters of a directional well.
The radius of curvature is the most common method to estimate the trajectory in the curved section.
When performing survey after the well is drilled, survey intervals are typically every 30 m. Generally,
we divide wellbore trajectories into 3 main types:
Build and Hold
Build-Hold and Drop
Continuous build
Figure 4-1: Type of directional wells.
To carry out the geometric planning for a Type I well, the following information is required:
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AZIMUTH, a The azimuth of a wellbore at any point is defined as the direction of the wellbore in
a horizontal plane measured clockwise form a north reference. Azimuths are expressed in angles
form 0-360°, measured form north = zero.
INCLINATION ANGLE, b The inclination angle of a well at any point is the angle the wellbore
forms between its axis and the vertical.
KICK-OFF POINT: The kick off point is defined as the point below the surface location where
the well is deflected from the vertical. The position of the kick off depends on several parameters
including: geological considerations, geometry of well and proximity of other wells.
BUILD UP AND DROP OFF RATES: The optimum build and drop off rates in conventional
directional wells are in the range of 1.5° to 3° per 100 ft, although much higher build rates are used
for horizontal and multilateral wells.
4.2. Estimating the trajectory.
Two of the most applied methods for trajectory estimation follow below.
4.2.2. Tangential Method, for straight sections
In this model the wellpath is assumed to be a straight line, defined by the inclination and the azimuth
at the lower survey station (station 1), as seen in Figure 4-2. Notice that the angels measured at
station 2 are not used in the analysis.
Station 2
DZ
b
N
DN
DH
DE
a
E
Figure 4-2: A 3D projection of the trajectory.
From Figure 4-2 it can be seen that:
DZ = L * cos b
(1)
DH = L * sin b
(2)
DE = DH * sin a
()
DE =DH * cos a
()
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This method gives clearly large errors in wellbores when the well direction is changing significantly
between stations. In wells where even over relatively short intervals there can be significant changes
in azimuth and inclination, this method is not recommended. Alternative method are the Average
Tangential Method (taking the average inclination and azimuth in two consecutive stations), or the
radius of curvature if the well forms a continuous curvature.
4.2.3. Radius of Curvature Method
This method assumes that the wellpath is not a straight line but a circular one, both in the vertical
and in the horizontal planes. The arc is tangential to the inclination and azimuth at each survey
station. See Figure 4-3.
Here we compare the complete circle with the small sector created by drilling between two
measuring stations, the Measured Length (DL), and the angle change (Da). During building
inclination, it is called Build Up Rate (BUR). In general, we call it Dog Leg, which, for a circle is
constant. Any deviation from the constant BUR we call Dog Leg Severity (DLS). Eqn. 4.4 compares
a full circle with a segment or an arc of the circle
2R / 360 = DL / Da
()
Figure 4-3: A well curved in two planes.
The wellpath can therefore be described as an arc in both planes.
In the vertical plane:
Angle change in the horizontal plane = a2 – a1. For a circle, we have:
(a2 – a1) / 360 = DL / (2 Rz)
(4.5)
Rz can be found from solving eqn. 4.1.
Rz = L * / (a2 – a1) * (180/)
(4.6)
Knowing Rz we may now calculate DZ:
DZ = Rz * sin a2 – Rz * sin a1 = R (sin a2 – sin a1)
(4.7)
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Substituting for Rz, the vertical increment becomes:
DZ = L / (a2 – a1) * 180/  * (sin a2 – sin a1)
(4.8)
The horizontal increment can be found through:
DH = Rz (cos a1 – cos a2)
(4.9)
In the Horizontal plane:
Angle change in the vertical plane = b2 – b1. For a circle, we have:
(b2 – b1) / 360 = DH / (2 Rh)
(4.10)
Rh can be found by solving eqn. 3.10: Rh = DH / (b2 – b1) * 180/ 
DN = Rh * sin b2 – Rh * sin b1 = Rh (sin b2 – sin b1)
(4.11)
Substituting for Rh:
DN = DH / (b2 –b1) * 180/  * (sin b2 – sin b1)
(4.12)
Substituting for Rh:
DN = Rz (cos a1 – cos a2)/ (b2 –b1) * 180/  * (sin b2 – sin b1)
(4.13)
Substituting for Rz:
DN = DL * / (a2 – a1) * (180/)2 * (cos a1 – cos a2) * (sin b2 – sin b1)/ (b2 –b1)
(4.14)
Note that DL = MD and that Da/MD = BUR in degree/m
4.3. Directional drilling vs. equipment
We present the directional equipment along with the activity of developing the directional wellbore.
a. Making the initial deflection from vertical
The initial deflection can be achieved by means of two different equipment systems:
1. Whip stock (see Figure 4-4)
The original way of deflecting the wellbore was by means of the whip stock. The mechanical
whipstock is permanently anchored in the well and oriented towards in the desired direction.
Most whip stock are set on the bottom of the hole or on top of a high-strength cement plug,
but some are set in the open hole.
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Figure 4-4: Deflecting from vertical with a Whipstock.
2.
Bent sub + mud motor (see Figure 4-5)
After vertical, when start on the kick off section, the rotary assembly is replaced with a
steerable motor. The steerable motor is usually a positive displacement mud motor inside a 1º
to 3 º bent housing. When mud is flowing, the motor rotates the bit, but not the drill string.
This type of drilling is called sliding mode.
Figure 4-5. The bent sub (deflection device) and the mud motor.
b. Drilling the curved section
The curved section can be directionally drilled by means of three different equipment systems:
1.
Bent sub + mud motor
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2.
BHA for directional drilling. Manipulate Only possible to change inclination.
Fulcrum (increase I) of pendulum (dropping I) assembly Downhole adjustable stabilizer. Used
instead of standard BHA
3. Rotary steerable system
For option 2. and 3. See more detail further below:
c. Drilling the tangent section
The tangent section can be achieved by means of two different equipment systems:
1.
Bent sub + mud motor (sliding drilling; the drill string does not rotate)
2.
Standard BHA. Use the packed hole assembly (see below)
BHA for directional drilling
Stabilizers and drill collars are the main components used to control hole inclination, as shown in
Figure 4-6. There are three ways in which the BHA may be used for directional control:
Pendulum Principle
Fulcrum principle
Packed hole stabilization principle
→ Decreases I
→ Increases I
→ Holds I
Pendulum Principle: The pendulum technique makes the angle drop, especially on high angle wells
where it is usually very easy to drop angle. The pendulum technique relies on the principle that the
force of gravity deflects the hole back to vertical.
Fulcrum Principle: This is used to build angle (or increase hole inclination) by utilizing a near bit
stabilizer to act as a pivot or a fulcrum of a lever. More WOB will increase the rate of angle build.
Packed Hole Stabilization Principle: This is used to hold or maintain hole inclination and direction
and are typically used to drill the tangent section of a well. The packed BHA relies on the principle
that two points will contact and follow a sharp curve, while three points will follow a straight line.
Packed BHA have several full gauge stabilizers in the lowest portion of the BHA, typically three or
four stabilizers, making the BHA stiff.
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Figure 4-6: BHA-manipulation to control inclination.
Rotary steerable systems (RSS):
Several solutions of RSSs are completing, and to exemplify we present the Autotrack. It combines an
automated downhole guidance system, formation evaluation sensors and two-way communication
with the surface. The steering direction is defined by pressure distributed selectively to three stabilizer
pads on the non-rotating sleeve. Any deviation from the programmed well path is automatically
corrected through closed-loop control without interrupting drill string rotation.
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Figure 4-6: Autotrack DDM.
5. Wellbore Stresses
The objective of measurements is to enable maintaining an efficient and trouble-free operation.
5.1. Surveillance of the drilling process
When
a failure occurs, symptoms, which are seen in the drilling data, is followed by a diagnosis of the
failure. This will help reducing non-productive time (NPT). On average NPT is typically in the range
of 15 % of the total rig time but can become higher during drilling of complex wells. Detection of
symptoms followed by diagnosis is especially important in complex wells. Time-based drilling data
can be evaluated and transformed into useful symptoms for automatic diagnosis.
Concepts often applied in conjunction with surveillance are:
Symptom: A deviation of the expected or normal performance
Normal state: The state when the process or the data are performing as expected
Error state: Error is a state in which a process or a hardware is less functional, but do not cause any
immediate loss of time
Failure state: Failure is a state in which a significant unplanned stop in the process occurs or the process
becomes less efficient and thus a significant NPT is involved. NPT is normally the result of a
repair activity, the activity necessary to bring the process back from failure state to normal state
5.1.1. Surface collected data
Surface recorded data in real-time are more common than downhole data. Figure 5-1 presents typical
variations of common drilling parameter.
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Parameter variation
Soft stringer encountered
Making a cnx
Hook Load
Bl o
picall
ht, ty
ig
e
w
Dead offshore
n
50 to
ck
Wiper trip
po
y
f.b
Of
si t
ion
om
ott
n
tio
fric
tes
t
time (h)
0
0.5
1.0
1.5
Figure 5-1: Variation in common surface data vs. time. In presented example we can observe soft stringer,
wiper trip and off-bottom test.
Surveillence of the drilling process in order to detect symptoms of the common failure; mechanically
stuck pipe. Downhole restrictions leading to mechanical stuck pipe can have (at least) two different
causes:
1. Wellbore geometry restriction:
a. Accumulated cuttings or cavings
b. Blocks restriction (blocks are large, irregular pieces of rock fragments either from
unstable wellbore or from cement)
2. Wellbore wall geometry restriction; swelling of shale or creeping wellbore
Table 5-1 presents some of the symptoms, which are characteristic for mechanical stuck pipe, enabling
us to distinguish between other failure types.
Table 5-1: Example of restrictions and interpretation of common drilling events related to stuck pipe (but also
to other failures).
Event
Plugging annulus
Symptom
• Intermittent ‘spiky’ or increased SPP
• Torque fluctuations
• Overpull / Took Weight
Cuttings-load formation •
•
•
Gradual increase of ECD
Low cuttings level expected at surface
ROP decreases
Comments
If close to plugging the annular path,
pressure spikes are seen
Packoff may be broken through before the
formation fractures
Need data agents to see these small
deviations / signatures
Increased RPM will increase cuttings level
The symptom called overpull is a signature of an irregular hook load that show sudden increments
during POOH as indicated in Figure 5-2.
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Normal HKL
Signature of
restriction
Figure 5-2: Overpull experienced when hook load (HKL) deviates from its normal level during tripping.
Tripping activity is seen by the upwards movement of the block position (BPOS).
5.1.2. Downhole data collection – MWD
The first measurements-while-drilling (MWD) to be introduced commercially to the drilling industry
were directional data, and almost all the applications took place in offshore wells. Achieving reliable
readings in the harsh downhole environment was one of the challenges of MWD, as for the later
Logging While Drilling (LWD) technology. Another challenge was to provide wireline-quality
measurements.
MWD includes more detialied data stored in its tool memory. The tool have three major
subcomponents:
•
•
•
Power system → battery and turbine
Directional sensors → array of three orthogonal flux-gate magnetometers and three
accelerometers
Telemetry system → mud pulsing or, more resent, acoustic system
A large part of all lost-time incidents lasting longer than 6 hours are caused by failures related to
drilling mechanics. Therefore, effort is made to ensure that information related to drilling mechanics
are acquired. Such parameters are WOB, torque, vibrations, shocks and temperature.
If the oscillation-level or shock-frequency exceed a pre-determined threshold, a warning is transmitted
to the surface. The driller can then take corrective actions (such as altering WOB or RPM) and observe
whether the stick-slip, or the bouncing, or the whirling of the bit has stopped on the next data
transmission.
Good hole cleaning can be difficult to achieve. Cuttings tend to build up on the lower side of the
borehole. If buildup is not identified early enough, loss of ROP and sticking problems can result. A
downhole annulus pressure measurement (PMWD) can monitor backpressure while circulating, and,
assuming that flow rates are unchanged, it can precisely identify when a wiper trip should be
performed to clean the hole. PMWD can also help monitoring the MW, and optimize the equivalent
circulating density (ECD). Let it be said that also the surface parameter called stand pipe pressure
(SPP) will give the same information if it is evaluated carefully (through surveilling by a data agent).
Historically, drilling-dynamics-LWD measurements have not been commercially successful. Many rig
site staff choose to rely on surface measurements and on own experience. Two reasons for discrediting
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the integrity of LWD systems is several false alarm.
5.2 Wellbore Instability
Many drilling problems are related to wellbore instability. Wellbore instability is related to chemical
and to mechanical imbalance. In present chapter we will concentrate on the mechanical part.
Shear and tensile failure mechanisms are the two largest concerns, especially when drilling in shale.
These problems are time-consuming and expensive to fix. It is especially offshore that the rig costs are
high. Despite great efforts to reduce borehole instabilities, they remain a serious concern. Mechanical
instability can be classified into two groups;
1. Stress-related instability
o Tensile failure occurs at too high mud weight (MW). The stress in the tangential
direction is larger than the critical tensile stress T. Fractures are detected at the
surface as lost circulation. The losses will increase with increasing mud pressure,
and ranges from minor to total loss
o Compressive-failure occur at too low MW: The crushing of the wellbore wall
(shear failure) will worsen with decreasing pressure, ranging from small amounts
of cavings (breakouts) to total wellbore collapse
o Creep: Wellbores that stay open for a long time (weeks) exhibit a slow plastic
“flow”, tending to close the wellbore. It is especially claystone and Halite (NaCl)
which creep under stress. Anhydrite on the other hand, is strong and immobile.
Creep is potentially useful for creating a supportive barrier around the casing
2. Existing weakness in the formation
The failure mechanisms presented in paragraph 1 are valid also for formations with
weaknesses, only their rock properties are different from normal formations.
o Faults and stress zones crossing the wellbore may represent a weakness: Preexisting fracture and cracks are especially observed in limestone, chalk and in
brittle shale
o Inter-bedded formations: Between lithology changes, bedding angle close to
wellbore angle, anisotropy, heterogeneity, and strength anisotropy
o Naturally weak formations: Coal beds, conglomerate
o Unconsolidated formation: Shallow, loose sand, gravel, silt
To evaluate latter types of instabilities we are dependent on information that can indicates what type of
weakness has been encountered. Weakness in the formation, like sand and gravel often lack cementation
material and are referred to as an unconsolidated formation, a problem that occurs mainly at shallow
depths. The problem with unconsolidated formations is that they cannot be supported by hydrostatic
overbalance from the drilling fluid alone, and may fall into the hole and pack off around the drill string.
To drill such weak formations, at shallow depths, the mud should provide a high-quality filter cake to
help consolidate the formation so that hydrostatic pressure can "push against" and stabilize the annular
wall.
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5.2.1. Rock mechanics
Creating a circular hole and thus introducing drilling fluids to stable formations creates stress
concentration. This stress concentration, which differs from the far-field stresses, could exceed the
formation strength, resulting in failure. The circular hole also represents a free surface that replaces the
natural confinement, which can reduce the formation strength and trigger inelastic and time-dependent
failures.
Introducing foreign fluids into the formation may create a localized, elevated pore pressure. It can also
reduce the cohesive strength of the formation, depending on the fluid interaction with the formation
matrix. The foreign fluids will also change the capillary forces.
Before presenting mechanical failures, we present some important rock mechanical characteristics.
Loading-unloading
The formation and the cement sheath of the wellbore construction is exposed to cyclic loading and
unloading. The stress-strain relationship describes the way the formation’s framework of granular
material responds to the applied load, whether the material exhibits elastic or plastic, brittle or ductile,
stains-softening or strain-hardening behavior during loading.
Poro-elasticty
Poro-eslasicity is referring to the effective stress. This concept suggests that the pore pressure helps
counteract the mechanical stress carried by the grain-to-grain contact. In materials with no porosity,
like volcanic rocks, the vertical stress, z, is identical with the overburden stress, ovb:
z = ovb
(5.1)
In porous material, like in most sedimentary rock, the pore pressure, pp, supports the vertical stress;
parts of the overburden weight are carried by the fluid.
z-eff = ovb – pp
(5.2)
Viscoelasticity
“Creep” is a viscoelastic property or a time-dependent phenomenon that significantly contribute to
many instability problems. Especially if the wellbore stays open (un-cased) for more than a week.
Fracture toughness
Fracture toughness is a material property that reflects the rock resistance of an existing fracture to
propagate. For radial or “penny-shaped” fractures to propagate, depends on the tensile strength, T.
Shale and chalk have lower fracture toughness than limestone and sandstone.
Near-wellbore stress field
A wellbore drilled through a rock formation introduces a new stress field at the wellbore proximity. If
we assume a homogenous, isotropic rock mass, and further assuming that a mud cake differentiates the
wellbore pressure, pmud, from the reservoir pressure, pp, then the small extra, near wellbore stress is
defined by:
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add = pmud – pp
(5.3)
Tensile strength
In this course we limit ourselves to apply far-field stresses. This is a major simplification, and not
possible to do when studying stresses on the wellbore wall in detail. For the study of tensile stress, we
introduce and summarize important factors involved in fracture initiation in Figure 5-3. When
wellbore pressure surpasses the fracture pressure of the formation, a tensile fracture occurs.
Another simplification which we allow here, is that the magnitude of the two horizontal stress levels,
h (the lowest) and H, are assumed equal. This is especially true whenever the wellbore transforms
from elastic to a plastic state.
Figure 5-3: Important stress parameters in sedimentary formations. Compressive stress, leading to shear failure,
are normally found to the left og the pore pressure.
The wellbore will fracture in the direction perpendicular to the largest horizontal in-situ stress, and
breakout (shear failure) occurs in the direction of the largest horizontal in-situ stress as illustrated in
Fig. 5-3. This is well known, but valid only for vertical boreholes. The fracture and, breakout direction
alter with well trajectory, at least when the fractures are close to the wellbore.
At a high enough shear stress a fault zone will develop along a failure plane, and the two sides of the
plane will move relative to each other in frictional process as shown in Figure 5-4. When a shear failure
occurs, the failure angle, , is typically close to 450.
z
h

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Figure 5-4: Shear failure.
The wellbore pressure window
Mud weight (MW) should be calculated as a mean of preventing the initiation of tensile and shear
failures. In some formations, the MW should, in visco-plastic formations, such as certain types of salt
rock, prevent the formation from creeping. MW is an important consideration for treating wellbore
instability problems. We repeat that the MW is limited by two boundaries, which we follow up in the
two next sub-chapters:
•
•
The upper boundary is the pressure that causes tensile failure and drilling fluid loss
The lower boundary is the pressure required to provide and replace confining stress (which
was removed during drilling). The confining stress, if large enough, prevents shear failure, the
creation of a plastic zone, and plastic flow (creep)
5.2.2. The Mohr circle and its shear failure envlope
Many empirical criteria have been developed for prediction of rock failure. It is imperative to
understand the physical interpretation of those criteria before they are applied on problems associated
with wellbore construction. Such criteria are empirical. Generally, failure criteria are used to generate
failure envelope, usually separating stable and unstable regions. Although some engineers attempt to
linearize the failure envelop, such linearization is artificial. Of the three common criteria that are
useful to wellbore and to wellbore proximity failures, we select the Mohr-Coulomb failure criteria, and
present only that one here.
Circle construction
The procedure for constructing the Mohr’s Circle is as follows: Figure 5-4 shows that the failure
depends on the normal stress z. and Figure 5-3 converts stresses for Cartesian to principal stresses,
s1,2,3. In relaxed geological basins the counterparts have identical directions. This fact we apply for
the circle construction. Figure 5-5 presents the Mohr’s circle in two dimensions.

Figure 5-5: A Mohr circle and the square box present the stresses in principle stresses.
Radius is (1 – 2) / 2. Plotting the stresses  and  in a general direction  to the x-axis, we obtain the
Mohr’s corcle. Largest value of the shear stress occurs for  = 45 0.
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MC shear failure envelope
The failure envelope is determined from many Mohr circles. The envelope of Mohr circles in Figure 56 defines the failure line. Each circle represents a tri-axial test where axial force is applied to the core,
for different lateral confinement (assume 2 = 3). The axial stress (1), is increased until the core fails
at this specific confinement.
Shear stress, 
Initial in-situ
conditions
2
Normal
stress, 
Figure 6-6. Mohr’s circles with failure envelope. Constructed on basis of stress tests on core samples. Stress is
increased/ decreased until shear failure occurs.
The envelope is defined by a tangent line to all the circles. A linear approximation of the line is given
by eqn. 6.4:
 = y + 1 * tan
(5.4)
Here  is the shear stress, y is inherent shear strength, called the cohesive strength,  is the angel of
internal friction, and 1 is the effective normal stress acting on the grains. Tan is the internal friction
during failure. The factors y and  are coefficients should be determine experimentally. A deviation
from a straight line is very common for this criterion, which is solely based on shear failure.
Therefore, this criterion should be applied only to situation for which it is valid.
Recording shear stress
Once we have drilled a wellbore and the stress concentration field is established, the rock will
withstand either the stress field or yield, resulting in a near-wellbore breakout zone that causes
spalling, sloughing, and hole-enlargement.
The above stated solution is valid only for elastic rocks. However, when a wellbore is penetrating an
intact formation, a plastic region is developed in the proximity of the wellbore, extending a few
wellbore diameters before an in-situ elastic region prevails again. The plastic region can create many
wellbore instability problems during drilling. In the pay zone, due to production, the plastic region
may propagate deeper into the reservoir, causing sand production. The size of the plastic region must
be known for evaluation of wellbore stability, perforation and sand production.
By lowering the formation pressure below its collapse pressure, the formation will experience shear
failure in the borehole wall resulting from high tangential stress. In older consolidated clay (in deeper
wells), which is hard and brittle, the wall will splinter under compressional stress and cave or slump
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into the hole. This leads to hole-enlargement and possibly bridging of the wellbore when combined
with inadequate hole cleaning. As the wellbore pressure drops further below the collapse pressure,
e.g., during the final stages of a gas blowout, the well will collapse and become packed with crushed
wall material, and the blowout will eventually come to a stop.
During the initial stage of a collapsing well, the cavings, eventually arriving at the shale shaker, can
indicate what is causing the problem. The information that potentially can be gained from cavings is
pointed out in Figure 5-7:
Splintery cavings
from underbalanced
drilling in shale
Angular cavings, shear
failure due to excessive
horizontal stress
Tubular cavings with parallel,
smooth, flat surfaces indicating
pre-existing, natural fractures
Figure 5-7: Surface symptoms of sub-surface mechanical stress-problems, revealed from the geometry of the
cavings. Cavings are always larger than cuttings, the largest dimension being typically 3 cm.
5.2.3. Tensile failure
Although this topic was presented in the Core course, we repeat it here with a few additional details.
Tensile failure model
Many of the more recently developed correlations have used the Eaton correlation as basis.
The Eaton correlation states that adding a specific amount of additional stress, min, to the pore pressure,
will cause the rock to fail in the direction perpendicular to the direction in which the rock can
withstand the least stress. A tensile fracture arises when well pressure reaches:
𝑝𝑓𝑟𝑎𝑐
= 𝑝𝑝𝑜𝑟𝑒 + 𝜎𝑚𝑖𝑛
(5.5)
This was shown in Figure 5-3. Tensile strength, sT, is very low for most sediment rocks, and often
assumed zero. It is rather split along one, or several, fracture planes, and therefore often originated
from pre-existing cracks. This is one of the reasons why the failure envelope is not always a straight
line.  has two synonyms: h and x. Instead of the x, y, z -coordinates, h, H, z- directions are
chosen. Our task is therefore to estimate h, expressed with familiar parameters. In accordance with
Hook’s Law (see Figure 6-8) the parameter h is expressed as:
min
h = Fh / A = E * h = E * Dlh /l
(5.6)
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z
Z - r
Compressive strength
H
Yield
strength
h
Elastic
Ductile
Brittle
z
z
Figure 5-8: Hook’s Law of elastic deformation. Uniaxial to the left and tri-axial to the right.
In the h-direction, which is devoted to the weakest stress-direction, the relative deformation is:
h = h / E
(5.7)
In a 3D setting the axial deformation is counteracted by a negative deformation in the two other
directions:
z - h - H = 
(5.8)
z / E –  * h / E –   H / E = 0
z –  * h –   H = 0
(5.9)
An expression of stress in the weakest direction becomes:
h = min =  / (1- ) * z
From eqn. 5-5 we have:
pfrac = ppore + h
pfrac = ppore +  / (1- ) * z
(5.10)
(5.11)
(5.12)
Recording tensile failure in the field
Fracture pressure is determined through a leak off test (LOT) which was covered in the Core course. A
LOT, also called formation intake-strength-test, is determining the tensile strength of the formation at
the casing shoe. The purpose of the LOT is to investigate the wellbore capability to withstand pressures
immediately below the casing shoe in order to allow for proper well planning with regard to safe
maximum mud weight, and to determine the setting depth of the next casing string.
Further pumping, beyond the leak off pressure, would start fracturing the rock until a sharp pressure
drop is observed, at which the fracture propagates into the formation. The curve of such an extended
LOT , called XLOT, is presented in Figure 5-9. It is largely dependent on the permeability in the
formation to be tested. Normally, however, the casing shoe is placed in compatible shale, which is
impermeable.
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Sometimes a predetermined pressure limit is set for the pump pressure during a formation strength test.
A "maximum required mud pressure is recorded. The test is called formation integrity test (FIT).
Formation breakdown pressure
Pump pressure
Fracture propagation pressure
p LO
p FIT
Stable
pressure
pLO = 1.1 *  h
15 l
Pumped volume
Figure 5.9: XLOT. The linear pressure increase reflects the elastic properties of the fluid and the casing. The
first sudden pressure drop reflects the initial opening of the formation.
If a LOT is not available, the following approximation can be used, as indicated in Figure 5-9:
pLO = 1.1. h
(5.13)
The possibilities of penetrating zones and layers further down in the well section with different
lithology and lower tensile resistance must be considered.
5.2.4. Summary of all failure types
Most wellbore stability problems occur in shale formations. Unfortunately, shale properties range from
very soft to very hard, and form very laminated to very intact. Several mechanism cause wellbore
instability problems as indicated in Figure 5-10
To understand a failure mechanism, we have already decided to use the MC-failure criterion. Granular
material, such as sand, fails in shear, while for soft material, such as clays, plastic compaction
dominates the failure mechanism. To sum up, the following failure mechanisms can cause wellbore
and near-wellbore instability problems:
•
•
•
•
Shear failure without plastic deformation, such as a breakout
Tensile failure, causing the formation to part
Cohesive failure, equivalent to erosion, which can cause fines migration and production. This
occurs when fm = y and confining stress = 0
Creep, which can cause a tight hole during drilling
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Figure 5-10: Wellbore instability problems during drilling. Dilation (expansion) could be caused by cohesive
failure.
5.3. LC and countermeasures
Lost circulation will occur when the wellbore pressure is surpassing the lowest fracture pressure in the
open (uncased) hole.
5.3.1. Main reason behind LC; narrow pressure window
Narrow pressure window refers to a small difference between fracture pressure and pore pressure. It
represents the balance between lost circulation on one side and kick on the other side. This problem
occurs especially in wells drilled in deep water, in large depths (HTHP wells) and in long-MD wells.
In deep and long wells (will automatically become slim due to many casing sections) the friction
pressure in the small annular space becomes large while pumping: ECD approaches the equivalent
fracture density the deeper and longer the well becomes. Deep waters are associated with low fracture
strength. To sum up, the two main problems associated with deep wells, drilling either in deep water
or in long, slim holes:
1) Low pressure window
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2) High annular pressure losses
Annular hydraulic pressure loss depends largely on annular clearance. The annulus in between the drill
sting and the wellbore wall in slim holes is narrow. Above the bottomhole assembly (BHA) the ratio
between the outer wall and the drill pipe is less extreme (depending on the bit size).
Since the pore pressure gradient at some depth starts to increase (above its normal gradient; 1.025
kg/l) with depth, the relative difference between pore pressure and fracture pressure also decreases.
Figure 5-11 clearly demonstrates this fact.
Fracture pressure
Pore pressure
Depth
pfrac - ppore
Medium
Pressure
Medium
Wellbore depth
Figure 5-11: Pressure window vs. depth. Left: Exemplified at a “medium” depth, where abnormal pore
pressure starts to develop. Here the difference between fracture and pore pressure decreases. Right: The
pressure window vs. increasing depth.
Combining the effect shown in Figure 5-11with large water depth, the effect of narrow pressure
window becomes more dramatic. Figure 5-12 speaks for itself on this issue.
Fracture pressure
Pore pressure
Sea bottom
Depth
Pressure
Pressure
Figure 5-12: Onshore (left) and offshore (right) pressure window. For offshore wells it is small since fracture
pressure is lower relative to onshore wells (it is here assumed that the offshore abnormal pore pressure starts
at the same total depth as onshore).
Offshore fracture gradients are lower at the same relative depth since the overburden starts as a water
column. Not only lost circulation are related to low pressure window, but also kicking wells.
Fractures occur at the weakest point; normally located immediately below the casing shoe, as
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illustrated in Figure 5-5.
Fracture pressure prognosis
Pore pressure prognosis
Depth
Present MW
LOT point
ECD
Max ECD
Formation top
Pressure
Figure 5-13: Lost circulation parameters.
The lowest equivalent fracture density (EFD) is expressed in Eqn. 5.1. Hydrostatic pressures are
referred to the drill floor level.
EFD = (phydrostatic + pLO) / (g ⋅ TVDcs)
(5.14)
Typical problems related to depleted reservoirs are listed below and illustrated in Figure 5-14:
1. Small pressure window (while drilling above the reservoir) may lead to
1. Losses
2. Kicks, followed by underground blowouts, if the well is closed-in
2. Differential stuck (while drilling in the reservoir), caused by large pressure differences
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Simulated curved
based on field data
Note that origianl
pore pressure has
reduced to 7 ppg
Figure 5-14: Pressure in conjunction with offshore, depleted reservoirs. The exemplified
reservoir is depleted to a pressure equivalent to 7 PPG pressure gradient.
Most oil companies have developed their own Best Practice to avoid problems and costly downtime
when repair is required to combat LC. Typical Best Practise in narrow pressure-windows are aiming at
drilling with lowest possible ECD to avoid kick or losses:
•
•
•
•
•
•
Flow checks are taken on drilling breaks and possibly circulate bottoms up to determine if
a weight-pill is necessary during tripping out
Use WBM as far as possible. Utilize sweep-pills as deemed necessary to clean the wellbore
Run shaker with finest screen possible to minimize low-gravity-solids-content (LGSC) to
avoid viscosity increase
Use lost circulation material (LCM) when small losses are encountered
Use Gunk Squeeze when large losses are encountered
Use strength augmentation when large losses are expected, combined with FPR
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•
Apply dual gradient drilling when large losses are expected
We present here the three latter counter-measures.
5.1.2. Three counteractions to LC
1. Gunk Squeeze
When large losses are encountered it may become necessary with more dramatic counter actions than
LCM. One historically often applied method is Gunk Squeeze. Gunk Squeeze is a mixture of Bentonite,
diesel oil and cement (BDOC). Here is how it is performed:
Step 1:
Mix BDO and store in a tank
Step 2:
Pump a batch of BDO through the drill string. The batch has to be separated by a pre and post
flush of diesel oil to avoid gelling during pumping
Step 3:
When the batch hits water (WBM) it gels quickly, both in the well below the bit and also inside
the fractures. The batch forms a base for the cement plug that follows some 100 feet behind.
The DS is pulled slowly into the casing shoe while pumping cement
Step 4:
After WOC, drill through the plug and set a casing
If the loss interval is long, a more complex methods must be applied; Wellbore Strength
Augmentation.
2a. Hoop stress – Wellbore Strength Augmentation (WSA)
This method involves added stress to the existing hoop stress. The method is performed in the
following way and demonstrated in Figure 5-15.
1.
2.
3.
4.
Create near-wellbore fractures
Pack fractures with selected solids (frac-and-pack)
Collapse the fractures onto the solids by releasing the pressure
Tangential compressive stress level has increased
Figure 5-15: The principles of how to increase the hoop stress (van Oort et al., 2011).
The increased hoop stress can be estimated through eqn. 5.15.
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Dp = /8 . w/R . E / (1 – 2)
(5.15)
Here w is the fracture width at the base, R the wellbore radius and  is the Poisson’s ratio.
The hoop stress increase is referred to as the Wellbore Stress Augmentation, and the resulting effect
during a leak off test is presented as fracture integrity pressure (FIP) after WSA treatment in Figure 516.
The WSA method has been tried out with success in the field. The stress increase is governed by w in
eqn. 5.2, which is equal to the diameter of the bridging particle. This method is also referred to as the
Designer Mud Concept.
One major problem associated with WSA is: If the new fracture resistance is surpassed (which
happens frequently during WSA), the wellbore fracture resistance drops down to or below its original
resistance! A follow up methodology has become necessary; FPR.
2b. Fracture propagation resistance (FPR)
FRP works by similar principles as TSO (tip screenout). FPR is being achieved by means of a
dehydrating filter cake, as soon as the fractures are created, which is sealing the fracture tip and render
difficult further propagation. The method works better in WBM than in OBM. In Figure 5-16 the
effect of FPR vs. type of mud is presented.
Surface pressure
FIP after WSA treatment
Lowered fracture
resistance after WSP
treatment is surpassing
obtained new margin
Initial FIP
Drilling margin
after WSA and
FPR treatment
Drilling
margin before
WSA or FPR
treatment
Volume pumped
Figure 5-16: Fracture integrity pressure (FIP) before (red curve) and after WSA (yellow curve) and after
FPR treatment (blue curve) (free after van Oort et al. 2011).
FPR is related to fluid leaking off into the porous formations and leaving a mud cake behind (true for
WBM) or creating a formation-internal tight filter (true for OBM). This is presented in Figure 5-17.
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Cake
Fluid
Tip
External filter cake
Fluid
Tip
Internal filter cake
Figure 5-17: Fracture propagation in WBM (left). External filter cake builds up, sealing the fracture tip. In
OBM (right) the fracture is allowing full pressure communication to the fracture tip, facilitating fracture
extension at a lower propagation pressure (van Oort et al., 2011).
WBM behavior:
1. Spurt loss
2. Dehydrated filter cake will pressure-isolate the fracture tip from full hydraulic force
3. Drilling fluid must now break through filter cake → higher fracture re-opening and
propagation pressure is necessary
OBM behavior:
1. Emulsion blocks the formation internally. No spurt loss or filter loss (this makes OBM the
preferred system for drilling depleted formation!)
2. Pressure isolation is now further inside the formation → Lower resistance of fracture reopening and propagation as compared with WBM
The Wellbore Strengthening Material (WSM) must consist of hard particles (sand or marble) to
keep the fractures open. Sand is combined with natural crystalline flake graphite, in the size of 5425 microns, to make a strong and thigh fracture.
3. Dual gradient drilling
An even more complex method than WSA / FPR is the Dual gradient drilling method. This method
requires a new organization of the drilling fluid circulation system. It is presented in the lectures.
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6. Drilling Fluid Temperature Modelling
This chapter includes estimation of the drilling fluid temperature in the wellbore.
To enable termerature estimation we must first know the ambient temperature. And in order to
estimate factors such as expansion of drilling fluids, change of fluid viscosity or variation in other
fluid properties as a function of temperature, we also need to estimate the fluid temperature variation
in the well.
6.1. Temperature issues
Temperature has a general effect on metals and plastics:
y reduces 0.03 % / 0F (0.06 % / 0C). The Ultimate strength decreases. Elastomers become
hard and in-elastic at low temperatures. Thermo-plastic, on the other hand, are stable at high
temperatures.
Sometimes it is necessary to perform Annealing, a form of heat treatment of metals (alloys) and
plastics, indicated in Figure 6-2. The materials must be heated to above its re-crystallization
temperature (glowing), then slowly cooled. The material is now softened. Seen as:
Increase their ductility, reduce hardness and make them more workable.
Temperature’s effect on fluids is well known, at least for water, as shown in Figure 6-2. The effect on
drilling fluids is less known:
First, OBM is more T-stable than WBM. But gelation may occur at high temperatures. This is mainly
caused by the fact that the colloids flocculate.
Use of cesium formate in WBM is expensive but make it temperature-stable.
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Figure 6-1: Anneleaning of the material Annealed.
Figure 6-2: Water’s viscosity and density vs. temperature.
Fluid’s density vs. pressure and temperature, in OFU (PPG, 0 F, psi) was found by Kutasov:
rWBM = 8.5 - 2.6 *10-3 T + 2.5 *10-5 p
rOBM = 7.0 - 3.0 *10-3 T + 4.4 *10-5 p
(6.1)
(6.2)
An onshore geothermal gradient is often taken to be 2.5 oC / 100 m depth increase. Offshore
geothermal gradients are heavily influenced by the ocean temperature, as clearly shown in Figure 6-3.
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Annulus
Geothermal
on land
Relative depth (%)
water depth
Geothermal
off shore
50
70
Drill pipe
100
0
Relative temperature
(%)
50
70
100
Figure 6-3: Sea temperature (left). Wellbore temperature profile in the annulus and in the drill pipe, after long
pumping period (right).
Heat capacity of water is high, and after shutting the pump off it may take typically a complete day
until the geothermal temperature profile is re-established in the mud.
A steady-state analytical model for computing mud temperature profiles is a result of heat conduction
through the solid material and heat convection at exposed walls. These two types of heat exchange we
first present individually before combining them into one model.
6.2. Conduction
Conduction through solid materials is governed by Fourier’s law:
q = - kA dT/dx
(6.3)
Here q is rate of heat transfer (W) and k is the thermal conductivity with units W/(m . 0C). Since heat
transfer is positive when temperature decreases, we must insert a negative sign. Conduction through a
plane wall (see Figure 6-4) with thickness  and axial length L:
q = - kA DT/ = - kA (T2 – T1) /  = kA (T1 – T2) / 
(6.4)
For a concentric cylindrical walls, the Fourier’s equation takes the form:
q = k2 L (T1 – T2) / ln (R2/R1)
(6.5)
A = 2 (R2 – R1)
d
T1
R1
L
1
T1
T2
R2
T2
L
Figure 6-4. Heat conducted through a flat wall and a concentric pipe.
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Thermal resistance is analogous to electrical resistance, which, according to Ohm’s law is: I = V/R.
The thermal resistance of a plane wall is, similarly: q = DT / R
If several walls in good thermal contact are involved, the rate of heat transfer for each section will
depend on the total resistance:
Rtotal = R
(6.6)
Leading to
q = DT / Rtotal
= DT / ( / (kA) )
(6.7)
For plane wall conduction:
R = 1 / (k1A1) + 2 / (k2A2) + …..
(6.8)
For cylindrical wall conduction, assuming same L:
R = ln (R2/R1) / 2k1L + ln (R3/R2) / 2k2L
(6.9)
For convective heat transfer (see next Chapter (6.3)):
R = 1 / (hA)
(6.10)
6.3. Convection
When a fluid comes in contact with a solid surface at a different temperature, the resulting thermalenergy-exchange process is called convective heat transfer. There are two kinds of convection
processes: Natural or free convection and forced convection. In the first type the motive force comes
from the density difference in the fluid from its contact with a surface at a different temperature, which
gives rise to buoyant forces. Typical examples of such free convection are the heat transfer by the air
along the walls of a house on a calm day or the convection in a tank in which a heating coil is
immersed.
Forced convection occurs when an outside motive force moves a fluid along a surface at a higher or
lower temperature than the fluid. Since the fluid velocity in forced convection is larger than in free
convection, more heat can be transferred at a given temperature difference.
In pipe flow heat is convected and transported by the drilling fluid. In Figure 6-5 heat is transferred
from a flat plate of solid material into a flowing fluid. The temperature gradient in the fluid depends
on how quickly heat is carried away by the fluid.
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T
v
Too
v(
r)
T (r)
Tw
x
Figure 6-5: Velocity and temperature profile above a flat body with temperature T w on its wall.
Regardless of whether the convection is free or forced, the rate of convective heat transfer of the liquid
adjacent to the wall, can be expressed through Newton’s law of convective cooling;
-𝑞 = ℎ𝐴(𝑇𝑤 − 𝑇∞ ) = r Qfluid . cp . dT
(6.11)
The heat lost form the hot body is identical to the heat gained in the passing fluid. Here h = average
convective heat-transfer coefficient at fluid-to-solid interface with units W / (m2 . K). cp is the heat
capacity of the fluid in J / (kg . K)
The numerical value of h must be determined experimentally. Table 6-1 list some approximate values
of convection-heat-transfer coefficients.
Table 6-1: Approximate values of convective heat-transfer coefficients, h (W / (m2 . K)), free or forced.
Material
Free
Forced
Air
Water
Water
Water
Oil
5 – 25 (radiator)
50 – 100 (heating oil)
100 – 500 (flow in pipe, slow – high)
50 – 3 000
50 – 350
10 – 50 (air heater)
900 – 2 500 (w-w heat exchanger)
500 – 1200 (flow in pipe, slow - high)
100 – 10 000
Newton’s law of convective heat transfer is simplified. It assumes that the temperature within the hot
or cold body is considered uniform (but slowly cooling or heating) at any time. The total heat
transferred from the body to the fluid when the fluid temperature has reached the temperature T is:
hA(Tw – Too)= r Qfluid . cp (Too – Tfluid original)
(6.12)
A more detailed study of the heat transfer coefficient would show that it depends on the fluid’s flow
regime (laminar or turbulent).
6.3. The composite overall heat transfers
In many applications of heat transfer, two fluids at different temperatures are separated by one or even
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a double solid wall. Heat is transferred from the fluid of the higher temperature to the wall, conducted
through the walls, and then finally transferred from the cold side of the wall into the fluid at the lower
temperature. This series of convective and conductive heat transfer processes is known as Overall heat
transfer, illustrated in Figure 6-6.
Fluid 1
k1
Fluid 2
Tfluid 2
k2
Tfluid 1
h1
h2
q
T1
1
T2
T3
2
Figure 6-6: Temperature profile for heat transfer through a double walled tube wall surrounded by two
fluids.
Here the overall heat transfer coefficient is valid
1 / (koA) = 1 / (h1A) + 1 / (k1A) +2 / (k2A) + 1 / (h2A)
(6.13)
The overall heart transfer coefficient k0 for the exposed area A. k0A was calculated using the quantities
already introduced for convective heat transfer and conduction. In practice values for k0 are often
given and used.
For flat walls all As are identical, and for tubes mostly the outer surface A2, does not normally differ
greatly from A1 or Aavg. Value 1/k0A represents the resistance to the overall heat transfer. It is made up
of the single resistances for each transfer process in the series, analogue to that in electrical circuits,
where the total resistance to the current is found by adding all the single resistances in series.
Therefore, the resistances which the heat flow q must pass though are added, first the resistance due to
the boundary layer in fluid 1, then conduction resistances in the wall and finally the resistance to
transfer of heat to the boundary layer of fluid 2.
For the overall heat transfer from inside of a double pipe, it is taken into account that the pipes have
radii R1 (inner), R2 and R3 (outer) and length L, and each has a surface of A = 2RL. Then it follows
that:
1/(kA) = 1/(h12R1L) +ln R2/R1 /(2k1L) + ln R3/R2 /(2k2L) +1/(h22R3L)
(6.14)
Conductivities and heat capacities for steel and water are presented in Table 6-2.
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Table 6-2: Material constants for heat transfer. All at 20 0C.
Materials
Density, r
(kg/l)
Thermal Conductivity, k
(Btu/hr/(°F . ft)
Thermal Conductivity, k
(W/(m . 0K))
1.3–3.33
Specific Heat, cp,f
(Btu/hr/(°F . ft)
0.2–0.625
Specific Heat, cp
(kJ/ (kg . 0K))
Chalk
2.4
Clay, sandy
2.5
0.6 – 2.5
1.38
Sand, saturated
2.5
2-4
0.83
Concrete
2.6
0.38–0.5
Olive oil
0.95
0.1
Engine oil
0.89
Formation gas
0.02
0.1–0.3
Water
1.0
0.36
0.58
0.997
4.18
Steel
7.87
40
60
0.09542
0.49
Cast Iron
6.9
Clear brine
1.25
0.17
0.4771
0.88
0.5
1.80
0.145
1.88
0.25
58
0.35
0.75
0.44
0.9
3.50
7. Completion
7.1. Completion fluids
The completion process prepares the well for production, and the fluids used at this stage of well
construction are called completions fluids. In the early days of drilling, the drilling fluid also served as
completion fluid, but after perforating became common practice, it was determined that using clean,
solids-free fluids for perforating would increase well productivity. These fluids, frequently composed
of brine, became known as completion brines.
In the 1980s and 1990s directional drilling technology led to horizontal and multilateral well design,
and sand control considerations became more critical for offshore wells in poorly consolidated
formations. As a result, completion technology became more complex with a number of new methods
for completing wells. As completion technology evolved, specialized completion fluid systems have
been developed to optimize completion practices. In the future, well completion designs will become
even more diverse, as will the fluids system have used in completions.
A completion fluid represents the bridge between traditional drilling fluids and stimulation fluids. The
phases of well construction can be subdivided into a drilling phase, a completion phase, and a
stimulation phase as indicated in Table 7-1. In its broadest sense, a completion phase includes every
step in the operation from the time the bit cuts the reservoir rock until the well is producing.
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Table 7-1: Phases in well construction
Phase
Activity
Fluid type
Drilling
Overburden drilling
Reservoir drilling
Drilling fluid
Drilling fluid
Completion
Perforation
Gravel pack
Cleanup
Placing equipment
Completion fluid
Completion fluid
Completion fluid
Completion fluid
Stimulation
Acid wash
Matrix acid
Frack pack
Hydraulic frack
Workover
Acidized fluid
Acidized fluid
Completion fluid
Completion fluid
Completion fluid
Clear brines are widely used in completion operations. A number of different clear brines are
commercially available, like sodium chloride, sodium bromide, potassium chloride and calcium
chloride. Lowest brine density gives lowest cost. There are three basic selection criteria for a
completion fluid: Density, crystallization temperature and chemical compatibility between the brine
and the formation. The fluid must also have adequate viscosity so that it can carry particles out of the
hole and finally, the ability to control fluid loss. It is desired that all fluid loss components of the fluid
are degradable so that they do not damage the formation for a long time.
The main components of clear brine (water + salt) completion fluids are:
1. Salt (for density)
2. Polymers (viscosifyers)
3. Fluid loss control
4. Formation compatibilty
5. De-foamers
6. Corrosion inhibitors / oxygen scavengers.
7. Bactericide
Obviously, all of the above components are used only when they are dictated by the particular
application.
Density requirements
The base liquid is usually brine, but, in some cases oil is used. The primary performance requirement
for a completion brine is pressure control. The density must be enough to produce a hydrostatic
pressure in the wellbore high enough to control formation pressures. Typically, an overbalance of 200
to 300 psi above bottomhole reservoir pressure is used for well control. Brine densities are commonly
reported at the reference temperature of 70 oF / 21 oC.
Table 7-2 gives maximum densities of clear brines commonly used in the oilfield.
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Table 7-2: Density of selected clear brines at 70 0F in ppg (1 kg/l = 8.33 ppg).
Salt type
Saturated brine density
Sodiumm chloride - NaCl
10.0
Potassium bromide - KBr2
10.9
Calcium chloride – CaCl2
11.8
Sodium bromide – NaBr2
12.8
Potassium formatted – KBr2
13.3
Calscium chl. – calcium br - CaCl2 – Ca Br2 15.1
Zinc bromide / calcium bromide
20.5
Weighting solids
When brine cannot provide the necessary density, acid soluble weighting material is used. Calcium
carbonate and iron carbonate are commonly used in completion fluids.
Particle size of these solids is important. They must be small enough to disperse easily. Exact size
requirements depend upon the polymers (type and concentration) used to suspend them.
Crystallization temperature requirements
After density, the crystallization temperature is the second most important selection criterion for a
completion brine. The crystallization temperature is the temperature at which the brine becomes
saturated as the temperature is lowered with respect to one of the salts that it contains, when cooled. At
the crystallization temperature, its least-soluble salt becomes insoluble and starts to precipitate. The
crystals can be either salt solids or freshwater ice.
Precipitation of salt in the brines when cooled below the crystallization temperature can lead to a
number of rig problems. If the salt crystals settle in the tank, the density of the brine pumped
downhole may be too low to control formation pressures. The brine appears to be frozen solid. It
cannot be pumped, and the lines are plugged. In deep offshore waters, the low temperature near the sea
bottom must be taken into account to prevent crystallization of bine when it is pumped downhole, past
the cold region.
Viscosifiers
HEC: Hydroxyl-ethyl-cellulose (HEC) is the most common polymer used to viscosify completion
fluids. It will viscosify all common brines. And its viscosity can be reduced (broken) by hydrochloric
acid or bacterial action when desired. The residue from the breakdown of HEC has been shown to be
non-damaging to formations. This is the reason for the popularity of HEC as a viscosifier for
completion fluids.
X-C Polymer: X-C polymer (biopolymer) is also often used in completion fluids. X-C polymer
appears to be somewhat more damaging than HEC, but, if used properly its damage to the formation
can be minimized. X-C polymer develops gel strength when the fluid is static, whereas HEC does not.
Gel strength holds solids in suspension and thus resists settling of particles. X-C polymer is used
whenever it is important to suspend solid weighting material. Since X-C polymer will also suspend
damaging particles such as clay, scale, etc. it is usually not used in systems where solid weighting
materials are not required. HEC is used instead.
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Fluid loss control
Completion with clear brine should ensure that the fluid that actually contacts the formation is as
particle-free as possible. Sources of particles found in brines include the following.
•
•
•
•
•
Suspended solids in the makeup water
Insoluble impurities in the salts
Rust, scale, or dirt in containers and tanks used for transport or storage of brines
Solids from mud and cement incorporated into the brine during displacement
And cuttings if the brine is also used for drilling through the reservoir section
To obtain solids-free brine, it is often necessary to filter the brine either at a brine storage plant or in
the field as it is being used. Use a two-stage filtration process: Fist thorough a 10-micron filter
cartridge, then through a 2-micron plated cartridge.
Large overbalance pressure combined with high formation permeability and long perforated or
openhole intervals can cause substantial loss of completion brine into the formation. Loss of large
quantities of completion brines, especially heavy brines, can be expensive and may increase the
formation damage.
Solid fluid loss material: Fluid-loss control materials can generally be classified into two types: Solids
and colloidal materials. Solid fluid-loss material control fluid loss by forming a low permeable filter
slightly inside the formation sand face. This plugs the pore throats and effectively limits the rate at
which fluid can enter. Since these particles plug the formation, they will impair production unless they
are removed. In some cases, they can be removed simply by back-flowing the well. However, this is
not always effective.
Soluble solid bridging particles are used to insure that the bridging particles can be removed. Two
types are commonly used: 1) Calcium carbonate (acid soluble) and 2) Oil soluble resin. Salt can also
be used if the brine is already saturated with that salt. The oil soluble resin and salt particles will later
be dissolved by the produced fluids. However, acidation may be required to dissolve calcium
carbonate, if the initial water amount during production is low.
Particle size is an important characteristic of bridging solids. Medium particles-size must be 1/3 of the
average opening-size of the sand pores in order to ensure a tight filter.
One approximate rule of thumb for bridging particles used in sands and sandstone is:
Particle size (m) = permeability (mD)0.5
(7.1)
Mean pore size of 100-mD would therefore require a mean particl size of about 10 m.
Colloidal material: To obtain a low permeable filter cake colloidal material are used.
The permeability of a filter cake composed of both drilled out material (which is undesirable but
unavoidable) and colloids has been estimated to be as low as 10-5 mD.
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Calcium lignosulfonate and modified starches are used as filter cake building and fluid loss additives
in completion fluids. They are acid soluble and will bio-degrade when the pH drops below 8.0. They
have been found to be non-damaging to the formation. X-C polymer, polyacrylamide and guar gum
also aid in fluid loss control (how?).
7.2. Well completion
The content of chapter 7.2 and 7.3 are based on three sources: Bellarby (2009), Brekkan (2015), and
Economides at al. (1998).
Certain equipment must be placed in the wellbore, and various other items and procedures must also
be used to sustain or control the flow of production fluid. Such equipment and any procedures or items
necessary to install it, are collectively referred to as Well completion.
In early completions, casing was either installed at the top of the producing zone as an openhole
completion or set through the producing reservoir. Openhole completions minimize expenses and
allow for flexible treatment options if the well is to be deepened later. But such completions limit the
control of well fluids.
Although many wells completed in this manner are still operating today, this method of completion
has been superseded by cased completion, set through the producing reservoir and cemented in place.
Fluid flow is established by the creation of perforations that extend beyond the casing and cement
sheath, thereby connecting and opening the reservoir to the wellbore. Wells that are cased though the
producing reservoir provide greater control of reservoir fluids because some or all of the perforations
can later be cement off, or downhole devices can be used to shut off bottom perforations. However,
openhole wireline logs must be run before the casing is set so that the exact perforation intervals are
known.
Cased-hole completion are more susceptible to formation damage than openhole completions.
Formation damage refers to a loss in reservoir productivity, normally associated with fluid invasion,
fines migration, precipitation, or the formation of emulsions just inside the reservoir. Loss of
productivity is expressed as a skin factor, in the Darcy equation:
q = khDp / ( ln re/rw + s)
(7.2)
A positive skin value indicates that a well is damaged. In instances where the formation damage
extends only a few feet from the wellbore, the well may be acidized to dissolve the damage. Hydraulic
fracturing is a stimulation technique that creates a fracture that is intended to extend beyond the
damage area. More details on these two topics are given in Chapter 7.3 and 7.4.
With declining reservoir pressure and producing volume, production through smaller-diameter tubing
becomes necessary. As deeper, multiple, and higher-pressure reservoirs are encountered now-a-days, it
was recognized that completions-imposed limitations on well servicing and control, and designs
required improvement to meet increasing requirements for wellbore re-entry and workover operations.
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7.2.1. Goal of completion
Goals for a completion is to:
•
•
•
•
•
Achieve a desired (optimum) level of production or injection
Provide for adequate maintenance of the wells and surveillance of the reservoir
Be as simple, reliable and safe as possible
Be as flexible as possible for future operation or changes in well duty
Effectively contribute to the reservoir development plan in conjunction with other wells
One objective of completion is to reduce constraints, which the well might impose on the production
of the hydrocarbons from the reservoir. The well constraints, which may limit the reservoir potential in
the completion interval, are the following:
•
•
•
•
•
•
Skin damage
Geometric skin
Sand production
Scale formation in pipes and reservoirs
Production of unwanted fluids
Tubing size and restrictions to flow
To achieve the potential of the reservoir, well constraints should be reduced when economically
justified. For example, skin damage may be reduced by acidizing, while geometric skin is reduced by
adding more, or less, perforation.
Completion-solution differs significantly within fields. New well intervention and completion
engineers learn the completion process and material from the installation guides or procedures used in
the operation. Equipment selection is one of the key elements in completion design. Typical
components are presented in Figure 7-1, briefly introduced in the list below, and presented in detail in
Chapter 7.2.4.
•
•
•
•
•
•
WH / XT; to control the flow from/to the well
TRSCSSV or DHSV; a fail-safe valve to close the well in if the XT is damaged
Tubing; the pipe that contains the fluids to/from the reservoir
BR (bore receptacle); serves as a point of replacing the equipment above and absorber of axial
stresses
Production packer; anchors the tubing and protects the casing from corrosive fluids
Liner; seals off the reservoir so only the selected (perforated) zone is produced
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Figure 7-1: Basic completion equipment
7.2.2.
Completion operations
Drilling operations are performed to facilitate a completion, so the reservoir can be produced as
planned. The drilling was finished, and completion is about to commence as shown in Figure 7-2,
accompanied by an exemplifying case. The reservoir section must be free of cuttings and the well is
now filled with completion fluid. The completion operations are:
1.
2.
3.
4.
5.
Displace the drilling fluid
Run screen section with swell packers and gravel pack
Perforate
Run the completion
Cleanup. Test the well and initiate production
1. Displacing mud
Completion operations are performed in a clear and particle-free fluid called brine, i.e. water with salts
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for weight control. Thus, the first step before completion, or before drilling into the reservoir, is to
clean out the drilling fluid and replace it with brine. The filter cake will remain in the well, or a new is
made as discussed in Chapter 7.1.
During the clean-up or the displacement run in Figure 7-3, the inside part of casing will be scraped to
get a smooth casing surface before running the completion equipment. Often, the cleanup or
displacement run would be performed using an old bit with no nozzles. A dull bit would ensure that no
unintentional directional work or washout occurred in the openhole. Removing the nozzles would
ensure the lowest possible pumping pressure and enable higher rate for removing debris.
Figure 7-2: Well status after drilling to TD
Typical measures for a successful displacement are:
•
•
Circulate the mud extensively; bottoms up (BU) is not enough. Circulate until the temperature
of the returning mud increases to the same temperature as during drilling
Viscous pills can be used to separate between the high-rheology mud and the water-like brine.
Pill-viscosity should be in the same range as the drilling mud to displace mud efficiently. Soap
acts along the casing surfaces to remove the adhesive mud
Some of the well cleaning tools are:
Magnet with metal swarf, junk trap or catcher, venture-baskets or vacuum cleaners, and scraper. The
junk trap will catch solids. The scraper tool contains spring-loaded knives.
Next comes the preparation of the wellbore wall. Normally we case and cement it or prepare it by
means of a screen.
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Figure 7-3: Clean-up or displacement run.
2a. Run screen section with swell packers and gravel-pack
The screens and a blank pipe, i.e. regular unperforated liner joints, are shown in light gray color in
Figure 7-4, upper part. The gravel pack tools and wash pipe are shown as a colored string inside the
blank pipe string. The drill string is shown in dark gray color on the top part of the upper figure.
If the filter cake is no longer effective; i.e., the gravel has eroded it away, the overbalanced brine will
flow into the formation, causing fluid loss. If loss rate is high, the completion operations cannot be
safely performed due to limited remaining volume of brine available at the surface. The loss has to be
addressed. With the installed screens, there are three ways to address the loss:
a) Circulate down flakes of carbonate with larger diameter than the screen openings, as deep as
possible. The loss rate will drag the particles to the loss area, and sealing off the loss area from
inside of the screens
b) Re-establish fluid loss barrier on the gravel face. Circulate fluid with small particles that can
go through the screens but large enough to block the pores on the gravel face
c) Establish fluid loss barrier on the wellbore wall / inside the reservoir
When pulling out the gravel pack tool string, a significant amount of gravel may enter the well. Large
bore packers, with low clearance between packer OD and ID of the screen section, have to be placed
accurately inside the swell packers. The drift run to clean out any obstructions may be necessary.
2b. Case, cement and perforate the cemented production casing
Details are presented in the lectures
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3. Run the tubing
The completion system that enters the screen section or the perforated casing as shown in Figure 7-5 is
now-a-day referred to as intelligent completion, due to complicated assembly of many lines for
different functionalities. Isolation packer provides functionality to seal off the annulus between the
completion and screen section. Below the isolation packer, there is a valve that chokes the production.
When the sleeve rotates, more slot openings are exposed, and the flow restriction is reduced.
Figure 7-4: Run screens with swell packers. In packed state to the right.
Check that all components are working. For intelligent completion, many lines must pass the
production packer. Special packers for smart completions have feeds that provide ways for lines, so
the electric and hydraulic signals can pass while the production packer ensures integrity.
A regular completion has to be spaced out; the lower end of the completion has a depth tolerance.
4. Terminating the lines and XT instrumentation
Before pulling the Tubing-Hanger Running Tool (THRT), barriers are tested. The configuration is
shown in Figure 7-6. Valves to the different zones are closed and the tubing pressure tested all the way
to the bottom. The un-perforated liner is pressure-tested to serve as a barrier, while the BOP will be
removed to land the Christmas tree (XT); the fluid will be no longer accepted as a barrier, because the
fluid level in the well cannot be monitored.
In most cases, a plug is installed at shallow depth, i.e. above the DHSV, so it can provide a second
barrier. After the installation, the plug is pressure tested.
All annuli should have pressure monitoring facilities and sample/bleed off points. Sample/bleed points
should be designed in accordance with good sampling practice, with grounding points, drains, etc.
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Configuration of the tree should be as follows:
•
•
•
A-annulus: In the event of a tubing or packer leaks, the A-annulus is likely to come under full
reservoir pressure. This annulus is the most important annulus and should be treated separately
from the B- and C-annuli. The A-annulus should have two flanged gate valves with the same
pressure rating as the tree on each outlet. The outlet used for sampling or gas lift should have a
profile to insert a backpressure valve. The other side may be terminated with a flange, needle
valve, and pressure gauge.
B-annulus: One outlet should have a single gate valve with a sampling/bleed down
arrangement. The other side may be terminated with a flange, needle valve and pressure gauge
C-annulus: One outlet should have a single gate valve with a sampling/bleed down
arrangement. The other side may be terminated with a flange, needle valve, and pressure gauge.
At this stage the THRT is ready to be pulled to surface. The control lines pressure is bled off.
The tubing head (TH), or the XT, see Figure 7-7, is mounted with a connector at the outside of the
WH, which contains pressure. The lines can now be accessed, e.g. so the DHSV can be operated.
Figure 7-5: Running the completion with down-hole instrumentation and control System.
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Figure 7-6: Landed completion
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Figure 7-7: TH with lines and termination.
The green TH has a yellow control line terminated at a small bore, on the WH with an external
connector. Connecting electric and hydraulic lines to the XT is referred to as instrumentation. For
subsea wells, everything is pre-installed and the XT or WH have penetrators, like a socket that plugs
into the TH to establish contacts.
5. Cleanup, test the well and initiate production
To avoid having completion or drilling fluids in the production system, wells are often cleaned up
separately. Conventional well testing is also performed. For oil wells with expected water production
and low pressure, a gas lift system is installed as shown in Figure 7-8.
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Figure 7-8: Gas lifting well on production.
7.2.3. Completion types
There are two main types of completion.
1. Tapered tubing vs. monobore
Monobore is a term indicating that the tubing has the same pipe ID from top to bottom, while tapered
tubing is a string with varying ID.
Tapered tubings require special expanding equipment that fit smaller tubings like 4 ½”. An example of
tapered tubing is shown in Figure 7-9, with well flow starts in a 5” liner, into the 7” liner window, then
past the 4 ½” middle completion, and finally into the 4 ½” x 5 ½” tubing.
There are some complications with tapered tubing:
1.
2.
3.
Setting a plug to isolate production in the 5” liner requires special expanding plugs that
fit through the 4 ½” tubing above.
Perforating the 7” liner requires perforation guns which have to fit through the 4 ½”
tubing and perforate a larger pipe (less optimal guns and charges have to be selected).
The velocity in the flow will vary going from 5” to 7” and then to 4 ½” pipe. Scale
deposits are often found in areas where there is a disturbance in the flow.
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Figure 7-9: Tapered completion
2. Dual completion
An example of a dual completion is shown in Figure 7-10. Within the completion, an additional pipe
(2nd pipe) is set and installed at a dual annulus packer within a large casing, typically 10 ¾”. This pipe
can be used for gas lift operation or production for a Formation 2. A well construction like this would
be found on floating platforms with dry XT, e.g. a TLP, on which the WH is located on the platform.
A wet WH can prevent the effect of temperature interaction with the sea by insulating it with nitrogen.
The Gravel Pack Packer (GPP) is similar to a liner hanger. A GPP must fit the gravel pack tool string
inside, so it has typically larger ID than a normal liner hanger.
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Figure 7-10: Example of dual completion.
7.2.4. Completion components
The goal of maximum productivity has high priority, but it is often balanced against constraints, which
could limit the achievement of the prioritized goal. This may include:
•
•
•
Cost: The cost to achieve higher production may be too high, due to the need to mobilize a high
cost completion
Completion material requirements: Will the usage of a larger tubing size result in significantly
higher well capex investment?
Anticipated production problems: Does the complete well design need to consider limits on
future production? This may be imposed by later wax or scale or by later gas or water
encroachment
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•
•
Need for well treatments: Does a downhole inhibition system need to be installed, thus limiting
tubing size?
Forecast need for workovers: It may be prudent to install a life-of-field completion rather than
go for maximum tubing size from day one.
Figure 7-11 gives an overview of what equipment is related to which design feature.
Figure 7-11: Completion design features and related equipment.
On the following pages we present these selected items:
1.
2.
3.
4.
5.
6.
7.
8.
Downhole safety vale (DHSV)
Production PBR
Production packer
Liner hanger PBR
Liner hanger
XT
Landing nipple
Sliding sleeve
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1. Downhole safety vale (DHSV)
Methods of well shut-in for safety and environmental concern at offshore locations is the control
device called surface-controlled subsurface safety valves (SCSSV). This DHSV is a fail-safe valve.
DHSVs, like Tubing Retrievable Surface Controlled Subsurface Safety Valve (TRSCSSV), will
automatically close the well if any critical damage (impact) occur to the XT so it cannot close in the
well.
DHSVs look like an “upside down toilet valve”, and it requires pressure support from a control line on
the surface to keep it opens. If the pressure in the control line is lost, the valve will close. In addition,
the well pressure will assist in closing it. Figure 7-12 displays the DHSV in open and closed position.
A DHSV opens by applying hydraulic pressure through a control line linked directly to a well control
panel. When hydraulic pressure is applied down the control line, the hydraulic pressure forces a sleeve
within the valve to slide downwards (dark green in Figure 7-10). This movement compresses a large
spring and pushes the flapper (Figure 7-13) downwards to open the valve. When hydraulic pressure is
removed, the spring pushes the sleeve back up and causes the flapper to shut.
Figure 7-12: DHSV.
The DHSV is normally installed at a shallow depth to reduce the potential volume of hydrocarbons
above it, but also deep enough to be saved from any impact damage that could occur to the XT.
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Figure 7-13: DHSV flapper and seat.
2. Production PBR
Polished bore receptacle (PBR), or production PBR, is an expansion joint (like a bicycle pump),
shown in Figure 7-14. The production PBR would be installed for two reasons:
1. Easy to perform a workover: For example, if a tubing leak occur, the old tubing is pulled at the
PBR, which parts by upward pulling
2. At the point where, extreme loads from pressure and temperature differences occur: The PBR
movement can reduce the tension or compression loads, compared to a completion fixed in both ends
Figure 7-14: Cut away view of a PBR. Male part below.
A shear ring makes it is possible to part the tubing in the PBR if desired. The rating of this shear ring
(or screws) would be set higher than the weight of the tubing string below (plus a margin), so it will
not shear during installation (while run-in). With a seal stack and restricted movement up and down,
the production PBR will maintain pressure integrity even after shearing.
The male part of a PBR is often run as the first joint in the upper completion, so it can mate up with
the female part of the PBR which is often installed at the top of the liner hanger. In this case, the male
part of the PBR would have a mule shoe at the end so it can easily enter the liner PBR as shown in
Figure 7-15. The oval mule shoe makes the tip rotate 120° when loaded / weight is set down at the tip.
Then, the orientation will change, so the completion easily enters the PBR.
Figure 7-15: Ratcheting (oval) mule shoe.
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3. Production packer
Where multiple reservoirs cannot be commingled, the zones are separated with a production packer.
Such packers are devices that are run on, or in conjunction with a string of tubing. The packer has a
rubber element that is extruded to form a seal between the tubing and the casing as shown in Figure 716 and 7-17.
Production packers seal off the annular space between the casing and the tubing. The annulus is
monitored with a pressure and temperature gauge. If the pressure increases in the annulus, the tubing
(primary barrier) is suspected to be leaking. The purposes of production packers are:
1.
2.
3.
4.
5.
Establish a barrier element in the primary barrier envelope
Protect casing from pressure or fluids in the tubing
Separate zones
Control subsurface pressure and fluid for safety reasons
Support artificial lift equipment
The production packer is also supporting the weight of the tubing because there is an anchor locked
into the casing wall. For full strength or pressure integrity, the packer needs to be set in a casing / liner
with good cement behind. Otherwise, the casing/liner will flex when forces are transmitted from the
packer to the casing/liner, and the packer will lose its pressure integrity.
Figure 7-16: Application of production packer.
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Figure 7-17: Production packer schematic.
4. Liner hanger PBR
The Liner PBR is the same piece of equipment as the Production PBR, only the functionality is to
enable a seamless transition from the liner to the tubing. The female part of the liner-PBR is installed
at the upper part of the liner, while the male part is at the bottom of the tubing. When the tubing is
installed / run into the well, these two components mate up with a constant ID from the perforations all
the way to the XT.
5. Liner hanger
The liner hanger holds the liner in place and / or creates a seal between the liner and the casing. It also
is an anchor and pack-off, much the same as the production packer. Once run to TD, the anchor is
activated, cementing is preformed and then the pack-off is set.
6. X-mas tree (XT)
All wells will have a set of valves at their top to close the well. They come in two versions; horizontal
XT (HXT) and vertical XT (VXT).
A Christmas tree is the crossover between the wellhead and the flow line to the production process. It
includes the connection through to wellhead and the downstream flange of the choke. A XT controls
the wellhead pressure and the flow of hydrocarbon fluids and enables the well to be shut off in an
emergency. It also provides access into the well for wireline, coiled tubing, and logging operations.
The tree must be designed to withstand all pressure levels such as at gas production, gas injection, and
the pressures arising due to a fracture or kill operation.
Solid trees are machined from a single block of material, while composite trees consist of standard
valves bolted together on a central body.
The advantages of using trees constructed from a single block of material (the axial part), as shown in
Figure 7-18, is the reduction of potential leak paths and has higher pressure rating. It is preferred to
use right angle outlets because it makes the internal inspection easier. To further ease the maintenance
and replacement, the flow wing and kill wing outlets should be studded. The solid type tree is also
used for dual completions.
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Figure 7-18: XT in green, WH in light and dark blue, TH in yellow.
7. Landing nipples
Many wireline devices can be performed by wireline-devises set in landing nipples. Landing nipples
installed into various wireline retrievable flow controls that can be set, locked, and carried by a lock
mandrel. If required, and depending on the tool’s function, the nipples can seal within the nipple bore.
The most common tools run are plugs, chokes, and pressure and temperature gauges. The main
features of a landing nipple are:
•
•
•
Locking groove or profile
Polished seal bore
No-Go shoulder (only on non-selective nipples)
Landing nipples are supplied in many ranges to suit most tubing sizes and weights.
The non-selective nipple type receives a locking device that uses a No-Go principle. The OD of the
locking device is slightly larger than the No-Go diameter of the nipple shoulder, as shown in Figure 719. The No-Go diameter is represented by a small shoulder located below the seal bore
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Figure 7-19: Non-selective nipple.
8. Sliding sleeves
An integral part of well completions is the sliding sleeve. The sliding sleeve provides annular access
between the tubing and the casing. It is used to produce a reservoir isolated between two production
packers and for circulating a well above the uppermost packer. The sleeve is opened or closed though
the use of wireline servicing methods.
A sliding sleeve or Sliding Side Door (SSD) is shown in Figure 7-20, and is installed in the production
tubing during well completion to provide communication between the inside and the outside of the
tubing. This is achieved when the sleeves are opened by wireline or coiled tubing tools. SSDs are
among other applications used for:
•
•
Killing a well prior to pulling the tubing during a workover
Providing selective zone production in a multiple zone well completion
Figure 7-20: Sliding sleeves.
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7.2.5. Pressure expansion of the tubing
We limit this chapter to address pressure expansion. Whenever a tubing is subjected to pressure
fluctuations, it will lead to both axial and radial strain. The two are related through the Poisson’s ratio
in eqn. 7.3. A minus sign indicate the two deformations move in opposite directions.
 = - Radial strain / axial strain
(7.3)
The effect of radial stress is often called ballooning. The ballooning force, Fb, is governed by eqn. 7.4.
Fradial = AiDpi – A0Dp0
(7.4)
Ao and Ai is the external and internal area respectively, Dpi and Dpo are the internal and external
pressure respectively. Hook’s law as given by eqn. 7.5 governs elastic deformations. In the axial
direction, we get:
axial = Faxial / Across section = E * DLaxial / L
(7.5)
Here  is stress, F is force, A is the crossed area and E the Young’s modulus. To transform radial to
axial stress, we assume stress and strain are linearly related, as suggested by Hook’s law, yielding:
Fradial / Faxial = 
(7.6)
Faxial = 1/ . Fradial
(7.7)
When Poisson’s ratio for steel is 0,3, the axial deformation or elongation from ballooning is obtained
by combining eqn. 7.5 and 7.7.
DLaxial = Faxial . L / (Across section . E) = Fradial . L /  (Across section . E)
(7.8)
7.2.6. Well barriers
A completion is the primary barrier envelope in most wells according to most operators’ design
philosophy. And it is the task of a completion to enable safe production or injection.
In Figure 7-21, a standard Well Barrier Schematic (WBS) is exemplified while running the completion
in-hole. The primary barrier would be the 7” liner - 9 5/8” casing and the completion fluid inside the
well. Minimum 100 % extra well volume should be available on the location to maintain a minimum
acceptable fluid volume and density in the well.
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Figure 7-21: A Well Barrier Schematic for a producing well during installing the completion.
The secondary barrier envelope goes through the cemented 7” liner including the liner hanger, the 9
5/8” casing with cement, and the WH. The inner casing is often referred to as the production casing.
When designing casing and tubing, a well construction with 7” x 9 5/8” pipe as production casing will
be certified with the same load cases: The production phase dictates the maximum loads of the well,
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thus sets the dimension for the primary and secondary barrier. The loads that determine the section
design pressure are summarized in Table 7-3.
Table 7-3: Load cases for casing (NORSOK D-10).
Item Description
1
2
3
4
5
6
7
Gas kick
Gas-filled casing
Production and/or injection tubing leaks
Cemented casing
Leak-testing casing
Thermal expansion of fluid in enclosed annuli
Dynamic loads from running of casing, including overpull to free stuck casing
If hydrocarbons flow in and cannot be excluded, the maximum section design pressure shall be
calculated with a gas-filled well, originating as section pore pressure, starting from TD. At the same
time, the section design pressure shall be limited to the leak-off pressure at the previous shoe. A kill
margin shall be included. Within the kill procedure, the rates and pressure of bullhead kill with
seawater should be specified, and so also the kill fluid. Unless kill margin has been specifically
calculated, it is recommended to use a minimum 35 bar kill margin (or higher for exploration and
HPHT wells).
Well integrity during TTD operations
To obtain increased recovery it is common to perform low cost infill drilling or perform intervention
in live wells, eliminating the need to kill the well. During Through Tubing Drilling operations, the
regulatory authority around the world requires two independent barriers against influx of pore fluids
In general for all drilling activities, the following barriers are common:
Well Barrier One:
Fluid column
Well Barrier Two:
1. Drilling BOP
2. Wellhead
3. Casing
4. Casing cement
Additional items belonging to Well Barrier Two are listed in Figure 7-22.
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Figure 7-22: Through-Tubing Drilling and coring operations with their two barriers.
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7.3. Fracture stimulation
The content of chapter 7.3 and 7.4 is presented in detail in two books; Bellarby (2008) and
Economides at al. (2002).
The basis of fracturing is relatively straightforward; pump a fluid at a high enough pressure down the
wellbore to force the rock open. The fracture then needs to be propped open with solids proppant.
They will hold open the created fracture after the injection pressure has been relieved and maintain
high conductivity in the fracture.
The fracture, filled with proppant, creates a narrow but conductive flow path toward the wellbore. This
flow path has a large permeability, several orders of magnitude larger than the reservoir permeability.
The narrow fractures, in one horizontal direction, can be quite long and will also cover a significant
height. Typical intended fracture widths in low permeability reservoirs are 0.1 in., while the length can
be several hundred feet.
In high permeable reservoirs, the targeted fracture width is much larger, perhaps as high as 2 in., while
the length might be as short as 30 ft. In almost all cases, an overwhelming part of the production flows
into the wellbore through the fracture. Therefore, the original near-wellbore damage (pre-made skin) is
bypassed.
To give some idea of the scope of fracturing, 50–60% of North American wells were in 2007 fracturestimulated as part of the completion program. As the frenetic pace of hydrocarbon developments
continue, many of the reservoirs previously considered uneconomic due to low permeabilities are
becoming attractive. There are two frequently encountered obstacles to applications of hydraulic
fracturing:
1. A widespread misunderstanding that the process is still only for low permeability reservoirs,
or that it is the last refuge for enhancing well production or injection performance, and thus to
be tried only if everything else fails. This is clearly not the case, and reservoirs with
permeability of several hundred mD are now routinely fractured.
2. At times, engineers in various companies outside of North America may try fracturing, but a
treatment is done so rarely and so haphazardly that it is bound to be very expensive.
For carbonate reservoirs, etching the fracture with acid can be used instead of or combined with
propping.
7.3.1. The fracturing process
The pressure required at the rock face to open a fracture (fracture initiation pressure) will be the
minimum principal stress plus an additional pressure to overcome the tensile strength of the rock,
indicated in Figure 7-23. In most reservoirs, the minimum principal stress is in the horizontal
direction.
The fracture will propagate perpendicular to the minimum stress direction. This will create a vertical
fracture in all cases except in thrust-fault regime, where horizontal fracture may be created. Stresses
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introduced in high-deviated wellbores may play a role in fracture direction close to the wellbore. But
fractures will quickly re-orient themselves when progressing away from the wellbore.
As the least principal stress often is in a horizontal direction, the resulting fractures will be vertical.
Fracturing jobs are designed to stimulate production from reservoirs. This often involves pumping
large amounts of fluid and solids (proppant), thus creating long fractures filled with proppant. A
massive hydraulic fracturing (MHF) job may exceed one thousand cubic meters of fluid and one
million kilograms of proppant. The fracture thus creates a high-permeability flow channel towards the
wellbore, which has a large drainage area towards the low-permeability formation. If the fracture was
not filled with solid material it would close when the fluid pressure drops.
Unintentional fracturing may occur during drilling operations, often referred to as lost circulation.
Today, hydraulic fracturing has several applications, such as:
•
•
“Frac and pack” operations in weak sandstone reservoirs. These are relatively short and wide
proppant-filled fractures, designed to penetrate near-well damaged zones and thus reduce the
pressure drop close to the borehole and hence also the sanding potential of the well.
Massive hydraulic fracturing jobs are normally preceded by a fracture test with a small
injection volume (min-frac) to determine the smallest stress in the formation and thus the
required fracking pressure and other design parameters of the fracturing job.
A linear elastic material is characterized by elastic constants that can be determined in static or
dynamic loading experiments. For an isotropic material, where the properties are independent of
direction, two constants are sufficient to describe the behavior;
7.3.2. Tip screenout (TSO) and fracture behavior
High permeability fracture (HPF) treatment is substantially different from conventional fracture
treatments like frac & pack. In particular, HPF relies on a carefully timed tip screenout to limit fracture
growth and to allow for fracture inflation and packing. This process is illustrated in Figure 7-24. The
TSO occurs when sufficient proppant has concentrated at the leading edge of the fracture to prevent
further fracture extension. Once fracture growth has been arrested (and assuming the pump rate is
larger than the rate of leak-off to the formation), continued pumping will inflate the fracture (increase
fracture width). TSO and fracture inflation is generally accompanied by an increase in net bottomhole
pressure. Thus, the treatment can be conceptualized in two distinct stages:
•
•
Fracture creation (equivalent to conventional designs): Injecting a relatively small fluid volume (pad)
followed by a 1–4 ppg proppant slurry
Fracture inflation/packing (after tip screenout): Once fracture growth has been arrested, further injection
builds fracture width and injected slurry will eventually pack to create a high proppant concentration.
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Net pressure
Closure pressure
Pump pad to
Initiate fracture
Pump low concentration slurry
Pump final stage;
the tip screenout occurs
Keep pumping; fracture
widens, but not lengthens
Figure 7-24: Width-inflation (see bottom right) with the tip screenout technique.
Final proppant concentrations of 20 lbm/ft2 are possible. Figure 8-24 also illustrates the common
practice of retarding injection rate near the end of the treatment. Coincidental with opening the
annulus to flow. Rate reductions may also be used to force tip screenout in cases where no TSO event
is observed at the surface.
The tip screenout can be difficult to detect. Bottomhole measurements may be supportive. Calculated
bottomhole pressures are unreliable because of the dramatic friction pressure effects associated with
pumping high proppant concentrations through small diameter tubulars and service tool crossovers.
The entire HPF process is dominated by the net pressure and fluid leakoff considerations, first because
high permeability formations are typically soft and exhibit low elastic modulus values, and second,
because the fluid volumes are relatively small and leak off rates high (high permeability, compressible
reservoir fluids, and low wall-cake building fracturing fluids).
As the fracture is propagating, the fracturing fluid is leaking off into the permeable formation. The
longer the fracture, the more leak-off there will be. The components that control the leak-off are
shown in Figure 7-25.
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Displacement and compression of reservoir fluid
Spurt loss prior to generation of reservoir fluid
Build-up of external
filter cake (if applicable)
Invasion of formation by liquid
components of the fracturing fluid
Figure 7-25: Propagating the fracture and controlling leak-off by means of the viscous pad fluid. The later
screen-off to the right.
As the liquid component of the fracturing fluid (the filtrate) invades and displaces the reservoir fluid,
this will create a pressure difference through the invaded zone due to the fluid viscosity and the zone’s
permeability. Therefore, fluids that maintain their viscosity also when inside the reservoir, for
polymers of relative short length will reduce the leak-off. For fluids that can generate a filter cake on
the fracture face (wall building), there will be an additional pressure drop through the filter cake.
Knowing that the leak-off is critical in designing a fracture treatment, the uncertainty in many of the
leak-off input parameters means that mini-fracs (also known as data-fracs) are routinely performed
prior to the main treatment.
The design goal for the minifrac is to be as representative as possible of the main treatment. To
achieve this objective, sufficient geometry should be created to reflect the fracture geometry of the
main treatment and to obtain an observable closure pressure from the pressure decline curve. The test
usually involves the injection of full-scale pump rates and relatively large fluid volumes into a small,
isolated zone (4 to 15 feet deep) at low injection rates (1 to 25 gal/min). The injection cycle is shown
in Figure 7-26.
Figure 7-26: Key elements on minifrac pressure response curve.
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Leak-off prediction
Initially, as a fresh fracture wall is gradually exposed, the filter cake will be non-existent and there will
be an initial (short lasting) fluid loss until the filter cake builds up. This is called spurt loss. The
external filter cake will stop growing when an equilibrium is reached, dictated by the reduced flow
through the filter cake and increased erosion of the cake by the fracturing fluids moving along the
fracture (like the dynamic filter cake on the wellbore wall).
Considerable effort has been expended on laboratory investigation of the fluid leakoff process for high
permeability cores. The traditional Carter leak-off model describes fluid leak off from fractures in high
permeability environments. The volume Vi injected into one wing during the injection time t consists
of three parts. The fracture volume, Ve, the leak-off volume, and the spurt volume Sp, using the
formalism, given in consistent units as:
Vi =Ve + 2AeCL√𝑡 + AeSp
(7.9)
Here Ae is the area of one wing surface. 2CL √t is the fluid leak to the formation. The two coefficients,
CL and Sp, can be determined from laboratory or field tests, similar to mud fluid loss in the filter press.
7.3.3. Proppant placement and clean out
The fracturing fluid transmits hydraulic pressure from the pumps and transports proppant (hence the
name carrier fluid) into the created fracture. The invasive fluids and excess proppant volume are then
removed (or cleaned up) from the formation, allowing for production of hydrocarbons important.
Proppant must oppose the earth stresses to hold open the fracture after releasing the fracturing fluid’s
hydraulic pressure, otherwise the conductivity of the (crushed) proppant bed will be considerably less
than the design value.
The two main categories of proppant are
•
•
Naturally occurring sands → the most common selection
Man-made ceramic or bauxite proppant → stronger and more expensive
Proppant can be resin-coated to reduce proppant flow-back. Sands are used for lower-stress
applications, in formation depths < 8 000 ft. Man-made proppant are used for high-stress situations in
formation depths > 8 000 ft.
Some of the considerations for pumping through a permanent completion are shown in Figure 7-27.
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Figure 7-27: Considerations for a fracture treatment through a permanent completion.
Almost all proppant treatments are over-designed, leaving some proppant in the tubing, as shown in
Figure 7-28. This has to be cleaned out prior to production. This usually requires coiled tubing,
although drillpipe can also be used.
Figure 7-28: Typical sequence for generating multiple fractures in a vertical well.
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7.4. Acid fracturing and stimulation
Acidizing
Acids create enhanced productivity by dissolving acid-soluble rocks, such as limestone and chalk
(CaCO3). Much of the theory of hydraulic (proppant) fracturing is applicable to acid fracturing as well,
especially the part regarding fracture initiation and propagation. Leak-off and fracture conductivity are
however fundamentally different. The most common acid system is hydrochloric acid which reacts
effectively with calcium carbonate according to the reaction
CaCO3 + 2HCl → CaCl2 + CO2 + H2O
(7.10)
It is less effective at removing calcium magnesium carbonate (dolomite)
CaMg(CO3)2 + 4HCl → CaCl2 + MgCl2 + 2CO2 + 2H2O
(7.11)
Other weaker acids are more expensive, less corrosive, and provide longer reaction times (greater
penetration). Hydrofluoric acid (HF) is occasionally used in sandstones for the removal of fines or clay
minerals. It is never used in carbonate reservoirs as it produces an insoluble precipitate (calcium
fluoride).
Pumping acid into the formation below the fracture pressure will dissolve the matrix. It generally does
this unevenly. This creates dendritic (branching) pathways into the rock. Such worm-holing is
beneficial as it increases the leak-off and generates correspondingly enhanced near-wellbore
permeability. Acidizing is the basis behind many matrix acid treatments where fracturing might risk
contact with nearby water or gas intervals.
Acid fracturing
Acid fracturing creates enhanced productivity by first fracturing and then pumping acid down the
fractures. The acid etches (dissolves) the walls of the fracture. Raw acid (especially hydrochloric acid)
reacts very quickly with the fracture walls and is quickly consumed. Alternatively, the acid leaks off
into the formation (accelerated by up to a factor of ten by wormhole formation), as shown in Figure
7.29.
Acid leak off accelerated by worm-holing
Figure 7-29: Acid displacement into a fracture + leak-off.
Predicting leak-off with acid is difficult. Although the reaction kinetics are readily predictable with
their associated mineralogy and temperature dependency, worm-holing can dominate and is difficult to
accurately predict and also difficult to measure experimentally. There is an acid concentration and rate
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dependency on the geometry of the wormholes. Acid fracturing leak-off is inherently harder to predict
than the non-reactive hydraulic fracturing fluids, but fortunately less important (no risk of premature
screen-out due to excessive fluid loss).
Controlling leak-off becomes a key requirement if a long etched fracture length is required. There are
a number of strategies:
1. Use a weaker acid might reduce leak-off
2. Injecting a viscous pad ahead of the acid will cool the rock, reduce leak-off and promote
viscous fingering (axial dispersion) of the acid through the pad
3. Increase the injection rate or conversely limit the number of intervals treated in one attempt
4. Viscosify the acid with a polymer. Once some acid leaks off, the pH rises and some wallbuilding leak-off control occurs
The treatment-fluid is over-displaced to prevent any acid left contacting the tubulars. As there are no
solids, acid stimulation can lack the excitement of screen-outs with proppant fracturing.
Without some form of diversion or sequential treatment of intervals, the acid will find the path of least
resistance into the reservoir. By further improving the conductivity of this flow path, it is unlikely that
acid will progress to treat other intervals. This will promote premature water/gas breakthrough without
significantly improving the productivity.
One specialized acid-fracturing techniques to counteract the least-resistance-path is presented here.
This technique has been much used for acid treatments and to a lesser extent for proppant treatments.
The technique relies on balls, approximately twice the diameter of the perforation entrance hole,
seating into these entrance holes and diverting the acid from interval to interval (Figure 7-30). The
typical treatment sequence is:
1. A cool-down pad of slick water
2. A cross-linked pad (leak-off control and viscous fingering)
3. An acid stage
4. A displacement stage
5. A diverter stage (containing a batch of balls)
Stages 2–5 are then repeated typically between 6 and 12 times without stopping. The acid will find the
path of least resistance and be subsequently diverted by the ball-sealers. At the end of the treatment, a
short surge ensures that the balls fall out of the perforations. Depending on their density, they then
drop to the bottom of the well or float to surface to be caught in a ball catcher (very coarse filter) prior
to production.
The technique requires a large number of perforations (between 100 and 300) otherwise diversion is
not guaranteed. Conventional balls are acid-resistant elastomers coating on a plastic core.
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Figure 7-30: Ball sealer diversion.
7.5. Work over operations
Workovers are performed to repair downhole equipment or surface valve and flow lines, and involve
shutting in production, and possibly retrieving and re-running the tubing. Since this is always
undesirable from a production point of view, workovers are usually scheduled to perform a series of
tasks simultaneously; renewing the tubing at the same time as changing the producing interval. Tubing
due to H2S (sour) or CO2 (sweet) corrosion may become so severe that the tubing leaks. That would
for certain require a workover.
Scale problem
Scale formation may occur when injection-water and formation-water mix together. Scale can
precipitate in the reservoir as well as on the inside of the production tubing. It can be removed
chemically from the reservoir and tubing. It can be removed also mechanically from the tubing.
Work over
Unwanted fluids are fluids from the reservoir with no commercial value, such as water and noncommercial gas. In layered reservoirs with contrasting permeabilities in the layers, unwanted fluids
appear first from the most permeable layers, through which the displacement is fastest. Layers, which
start to produce unwanted fluids, are detected by production logging tools and may therefore be shut
off by already installed equipment or by recompleting the wells. An underlying water zone may be
isolated by setting a bridge plug above the water-bearing zone; even without removing the tubing: Run
an inflatable though-tubing bridge plug as shown in Figure 7-31.
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Figure 7-31: Before and after recompletion of a well.
An overlying gas producing layer may be shut-off by squeezing cement across the perforations or by
isolating the layer with a casing patch called a scab liner, an operation in which the tubing would first
have to be removed. Such recompletion would be classified as a workover of the well. It would require
a rig or at least a hoist (for shallower wells).
A workover is a major intervention in a well and often the solution is to run a new tubing into the well.
Typical workover operations are therefore to replace production tubing due to leak and to run tools on
CT or on a snubbing string.
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8. Downhole problems
Downhole problems are important to understand in order to detect them and to be able to take the
optimal counter-action against them; drilling activity represents 50 % of all the spent cost in the lifetime
of an oil well, and 15 % of drilling activities are lost on repairing downhole problems.
Being able to reduce non-productive time (NPT) during drilling and to improve process quality are the
concerns of many researchers and engineers. Failures are defined as serious incidents, so serious that it
becomes necessary to perform repair actions (NPT) to restore the situation back to normal.
Errors, failures and symptoms
We differ between errors and failures. By process error is meant deviation from normal, expected
behavior. Errors may heal themselves or they may lead to a failure if not taken seriously enough. All
potential errors in the drilling process are presented in Figure 8-1. These are the errors we want to
detect and to use to identify failures and their cause. Figure 8-2 illustrates all potential failures.
Corresponding failures are also presented in Table 8-1, here with examples of their symptoms.
Work String Error
Hardware Error
In Equip-ment
Leaking Fm
High Compressive Stress
Errors
during
drilling
In Wellbore Wall
In Wellbore
High Tensile Stress
Chemical Reactive Wall
Accumulated Solids
Restrictions
Annular Error
Too High BHP
Too Low BHP
Bit Balled
No Signal From MWD
No Signal From DDM
Micro Stall In Motor
Leak To Fractured Fm
Leak To Intersecting Fault
Leak To Cavernous Fm
Leak To Fractured Fm
Leak To Intersecting Fault
Creeping Fm
Caving Fm
Ballooning Fm
Induced Fracture
Swelling Shale
Sloughing Shale
Dissolving Fm
Blocks
Accumulated Cuttings
Accumulated Cavings
Barite Dunes
Thick Filtercake
High BUR
Key Seat
HDLS
Leaking Annulus
Annulus Not Filled
Figure 8-1: Errors during oil well drilling, grouped with respect to location of where they occur.
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In Equipment
Failures
during
drilling
In Wellbore Wall
In Wellbore
Drill String Twist Off
Drill String Fracture
Rock Bit
Motor Stall
Blowout
Collapsed Well
Accidental Sidetrack
Kick
LC Induced
LC
LC To Weak Fm
SG
SWF
Cement Failure
Stuck Pipe
Differentially
Mechanically
Figure 8-2: Failures during oil well drilling, grouped with respect to location of where they occur.
Table 8-1: Technical failures during drilling, including subclasses of failures and their symptoms.
Location of failures
Failure
Failure SubClass
Symptom Example
Induced Fracture LC
Downhole Restriction
Lost Circulation
Natural Fracture LC
Lithology Change
Kick
High Pore Pressure Kick
Gas In Mud
Operational Related Kick
High Tripping Out Speed
Differential Stuck
High ECD-Eq. Pore Pressure
Unfavorable Wellbore Geometry
Local Dog Leg
Formation Related Low ROP
Hard Fm
Operational Related Low ROP
Wrong Bit Selection
Stuck Pipe
Mechanical Stuck
Undergaged Hole
Poor Hole Cleaning
Accumulated Cuttings
Wellbore Wash Out
Blocks Restriction
Increased Torque
Rock Bit Failure
Bearing Failure
Suddenly Increased Torque
Drill String Failure
Twist Off
Decreased HKL
Wash Out In Pipe
Decerased SPP
In the formation
Stuck Pipe
Inefficient ROP
In the wellbore
In the drilling equipment
Countermeasures to the problems
Every oil company and service company develop their own Best Practice. One example of Best
Practical involves the Drilling Limit. This is an approach where the well is drilled as fast as possible,
simultaneously ensuring a clean and a stable wellbore. The idea is to use best-in-class technology to
eliminate or at least minimize NPT by making a perfect wellbore. This principle is based on field
experiences and on many laboratory investigations.
•
•
Keep rate of penetration (ROP) to a maximum
Maintain high cleaning performance (learn to drill the dirties holes possible)
o
o
o
Keep high flow rate and high string-RPM
Ream / circulate only 1 – 2 minutes prior to connections
Use low mud viscosity to enhance turbulence in the annulus
If, in spite of applying Best Practice, a problem should arise, the problems need to be detected and
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understood. For this purpose, we present the six most frequently occurring failures during drilling. We
discuss them in detail, including underlying physics, how to detect them and practical counter
measures. The six problems are:
1.
2.
3.
4.
5.
6.
Lost circulation
Kick and related issues
Mechanically and differentially stuck pipe
Chemical stability of the wellbore, including swelling shale
SWF, SG and Hydrates (actually 3 different problems)
Gas migration in cement
The sub chapters are numbered with the same problem-number as in the list above.
8.4. Chemical stability of the wellbore wall
Shale makes up for more than 75 % of the drilled formations, and around 75 % of the downhole problems
are related to shale instability (mechanical and chemical). Shale properties range from very soft to hard,
and from very laminated to very compact. Shale-fluid interaction will alter the pore pressure.
The term shale is used for an entire class of fine-grained sedimentary rocks that contain substantial
amounts of clay minerals. The amount and type of clay content determine the shale’s affinity for water.
Smectite of the type called Montmorillonite reacts strongly with water for one main reason; shale
contains negatively charged clay minerals, and polar water is attracted to the mineral. Shale containing
Smectite has a greater affinity for water than shale containing Illite, Mica, Chlorite, Zeonites or
Kaolinite.
Drilling through shale formations with WBM allows drilling-fluid and its pressure to penetrate the
formation. Because of the low permeability of shale, the penetration of a small volume of mud filtrate
into the formation causes a considerable increase in pore-fluid pressure near the wellbore wall. The
increase in pore-fluid pressure may break the cohesive bonds in shale. According to Moody and Hale
(1993), there are three important chemical factors that affect wellbore stability.
•
The salinity of the drilling fluid in relation to the salinity of the formation pore fluid. This is
expressed as the water activity Aw which is inversely proportional to salinity.
•
Change in pore pressure is limited by the osmotic membrane efficiency. High efficiency indicate
high resistance of dissolved ions to pass through the shale.
•
Ion exchange capacity of the shale is important since the exchange of cations such as
K+, Mg++, Ca++ and Na+, in that order, weakens the shale (Na+ the most). Brines such
as KCl can control clay swelling, but where shale has low membrane efficiency the K+ is
gradually ion-exchanged and the shale experience delayed swelling.
Most shale formations contain water-sensitive clay materials such as Smectite, Illite and mixed-layer
clays, which absorb water that induces an elevated localized pressure. This pressure causes the shale
matrix to swell, disintegrate and collapse.
The following failure mechanisms summarizes how shale may fail due to chemical activity.
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In Figure 8-1 the three types of forces are repeated (from earlier chapters). It is the shear force which
governs rock failure. As shown in Figure 8-2 this may happen either when the cohesive strength
decreases, the pore pressure increases, or when the shear angel decreases. A change in the pore
pressure is controlled by the pore water flow. If a shale yields, its permeability will increase, and water
will flow easier; a self-accelerating process.
Figure 8-2: Three mechanical forces which may lead to destabilization of the sedimentary rock.
Stress-related instability is related to the rock strength, weak bedding plane, pore pressure and the
hydrostatic pressure in the wellbore. Shale may destabilize when water-based drilling fluid penetrate
compact shale. It is especially easy to destabilize existing fissures, fractures and weak bedding planes.
In the reservoir section, the sand cementation may become deteriorated, leading to sand production.
Engineers must examine sand formations and its degree and type of cementation through
mineralogical analysis.
To better understand the topic of chemical stability we introduce two governing processes:
•
•
Water transport through shale
Swelling pressure of shale
8.4.1. Transport of material through shale
In Table 8-2 the type of material transported, and its driving forces are introduced.
Table 8-2: Four types of driving force leading to two types of material flow (Hale at al. (1993)).
Flowing material
DpDl
D(chem.pot)/Dl
Water
Convection (direct transmission)
Osmoses
Solution / ions
Advection (indirect transmission)
Diffusion
The four driving forces are discussed below:
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1. Convection or water: During overbalanced drilling, the flow of water into formation is
governed by Darcy’s law.
dV/dt = kA/f ⋅dp/dr
(8.1)
2. Advection: Transport of dissolved material (ions) are moving together with the fluid
3. Osmosis: Water is transferred from regions of low salinity to regions of high salinity to reach
equal concentration.
pswell = RT/V ⋅ ln (pvapor,mud / pvapor,fm)
(8.2)
R is the universal gas constant, V the partial molar volume of pure water, pvapor,fm the aqueous
vapor pressure of the formation fluid, pvapor,mud the aqueous vapor pressure of the mud. The
quotient pvapor,mud / pvapor,fm is very close to the value of the water activity of pore water;
= Aw,mud / Aw,pore
4. Diffusion: Transfer of specific ions from regions of high concentration to regions of
low
concentration (the opposite direction of osmotic flow of water). Diffusion is expressed through
Fick’s law.
In addition to these 4 types of material flow, the pore pressure, created either by the hydrostatic mud
column and/or by swelling, will travel into the shale in accordance with the pressure diffusivity
equation.
When OBM is applied, the capillary pressure will dominate and take the place of the convective
induced flow. Capillary pressure is expressed through eqn. 8.3
pc = 2 c ⋅ cos  / r
(8.3)
OBM creates negative capillary pressure (cos 180 = -1) hindering water entrance. In shale the capillary
threshold pressure is very high due to very small pore throat.
Van Oort (2010) applied the flow-equations at an engineering level. applying (kshale = 10 -7 mD),
predicting the development of three fronts around a wellbore in shale as presented in Figure 8-3.
Figure 8-3: Extention of three different material fronts flowing into the wellbore wall while drilling in
overbalance and with balanced salt contetration (van Oort, 1997).
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Shale is so tight it cannot dissipate flowing water fast enough. Pressure therefore precede filtrate by 12 order of magnitudes further into the formation. Pressure will diffuse far ahead of the water front.
8.1.2. Swelling mechanisms
Swelling is a complex process. Osmosis is a powerful force and can in strength be compared to
congelifraction.
Osmotic pressure is important in clay. Some more details are appropriate: Argillaceous rocks
experience significant swelling by adsorption of polar water molecules or ions (such as Na+) onto
weakly charged clay sites. Water is attracted to the surface of the mineral but also into the opening
between unit layers with such a force that it will lead to increase distance between them, a
phenomenon called swelling. Swelling pressure can be predicted by equation 8.4 and the knowledge of
the water activity in the shale and the mud.
It is the difference in salinity that causes osmotic water flow, ΔAw = chemical potential. When ΔAw =
0 between pore water and mud, there will be no osmotic flow of water, hence no swelling and
accordingly no problems during drilling. Whenever there is a difference in Aw between clay and mud,
the swelling pressure is defined as:
𝑅𝑇
𝐴𝑤, 𝑐𝑙𝑎𝑦
𝑤
𝑤,𝑚𝑢𝑑
pswell = - 𝑉 ⋅ 𝑙𝑛 𝐴
(8.4)
Although shale is almost impermeable, the osmotic flow is determined by chemical potential or water
activity Aw in the mud and in the pore water. Aw is a measure of water’s salinity
Aw, distilled water
Aw, saturated NaCl
Aw, saturated CaCl2
= 1.00
= 0.755
= 0.295
When Aw = 1, the water has the highest possible potential.
KCl minimizes swelling due to small degree of hydration of K+. Potassium is generally regarded as
the most effective in making the clays less hydratable. And the geometry of Potassium ions is well
suited for entering the space between Montmorillonite unit layers as indicated by Table 8-3.
Table 8-3: Diameter of some molecules (in Angstrom).
Molecule
H
O
H2O
Not hydrated
1,6
1,3
2,9
Hydrated
1,6
1,3
2,9
K+
Na+
2,1
1,8
7,6
11,2
Ca++
3,0
19,2
Na SiO2
Clay pore throat
Clay fissures
6,1
10
20 - 2000
6,1
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Hydratable shale usually occurs at shallow depths (< 2 500 mTVD). However, swelling shale may also
be found at larger depth where the diagenesis process has been inhibited (like in high-pressured
formations). A typical problem in upper formation is: Shale swelling → weakened wellbore → erosion
→ expansion of the hole. Swelled shale becomes soft and sticky. During tripping operations the
expanded wellbore could possibly be scraped off by stabilizers and by the bit. Material accumulated
on the BHA during tripping may be observed in surface parameters as overpull and pack off (pack off
is seen only when the pumps are on).
At shallow and medium depths: Typical problems at medium depths are weakening of the wellbore –>
erosion of the hole: The swelling process is a slow process. When one layer of shale has swelled, it is
weakened, and therefore prone to erosion. The erosion could be both of hydraulic and mechanical
nature. The longer the wellbore stays open, the higher the probability is that the wellbore has weakened.
As soon as the wellbore has swelled, the erosion starts on the weakened layers, exposing new layers.
8.1.3. Inhibitive muds
The term «inhibition» has come to mean the suppression of hydration of clay, which means inhibit the
water to transform the shale into shale, to suppress swelling pressure.
Now we are ready to design inhibitive muds. They can be grouped into three types.
Type 1: Conventional inhibitive WBM. Example: KCl / PHPA
Type 2: Osmotic WBM. Example: CaCl2 + methyl-glucose
Type 3: Non-invading WBM or OBM
We will now compare the water transmission-ability of the two first ones through shale.
Type 1: Conventional inhibitive WBM: KCl / PHPA
Salt water muds are able to restrain the flow of water from the mud to the shale. This is
accomplishing by decreasing the concentration of free water molecules in the drilling fluid. In salt
water muds, large quantities of NaCl or KCl are added to the mud system, and the water activity is
largely reduced. When Aw, clay = Aw, mud , the formation will become stable. It has later become evident
that also salt type must match pore water salt type to completely eliminate swelling.
Reducing pswell in Smectite clay - young reactive gumbo type shale. KCl exhibits the highest inhibitive
effect of all salts.
+
Cations exchange place with Na ions, but have some shortcomings:
1. No filtrate prevention due to low base fluid viscosity, as shown in Figure 8-4.
2. High osmotic pressure suppression. But swelling pressure slowly climbing due to low
membrane effect (1 – 2%)
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Figure 8-4: Shale’s ability to transmit water through shale, recorded as pressure response in the base fluid of
conventional inhibitive WBM (van Oort, 1997).
Polymers, like PHPA, with functional groups of positive polarity absorbs onto clay surfaces at
multiple sites → they are more difficult to exchange/remove. Good inhibitors when low-molecular (<
10 000); penetrate pores of the shale. High molecular polymers, like PHPA, latches on to the outer
surface of shale in a web-like pattern and combat disintegration of shale. Pore blocking is minimal as
shown in Figure 8-5. Ideal additive for cuttings stabilization.
Figure 8-5: Shale’s ability to transmit pressure in conventional mud (van Oort, 1997).
Type 2: Osmotic WBM: CaCl2 + methyl-glucose
CaCl2 are highly soluble and can produce high fluid density. The salt suppresses osmotic pressure
(but due to low membrane efficiency (1 – 10 %) the suppression is limited over time.
The industry has realized that chemical instability is not possible to hinder with salt-addition alone,
due to low membraned efficiency of shale. Something more than inhibition is needed. The answer is:
Prevent water flow into shale. This is achieved by reducing filtrate invasion in shale, similar to
creating an internal filter in sand zones. Particles for this purpose in the mud must be smaller than the
pore throat in shale (approximately 10 Å).
Poly-glycerol and – glycols are saccharides of low molecular size (< 10 000). They viscosify the
filtrate / build an internal filter and retard filtrate invasion as shown in Figure 8-6.
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Figure 8-6: Shale’s ability to transmit pressure in a sucrose solution.
8.2. Offshore related challenges
The three upcoming challenges are all related to drilling in deep waters.
8.2.1. Shallow water flow
Shallow Water Flow (SWF) can be a problem when drilling with seawater returned to the mud line,
before the BOP and riser are installed. It may also be encountered after the BOP is in place. The origin
of the flowing water is weakly pressurized shallow, marginally compacted sands that are very porous
and permeable. We find them in areas where large river systems have transported huge amounts of
sediments (Mississippi, Amazonas, Zambezi, etc.)
Water flow rates can range from very low (below levels of detectability) up to several hundred liters
per minute and can often contain significant amounts of sand. The likely consequences of sustained
shallow flow include:
- Erosion of the sand zone
- Hole-erosion, and later, cement sheath erosion
- Flow behind the casing and later broaching to the surface where craters are formed
- Surface subsidence (into formed craters)
- Loss of conductor/template support (due to cement erosion)
Figure 8-7 illustrates some of the mentioned problems. SWF may not be noticed at first as the upper
well section are drilled riser-less, or, the weak zone above may be cased off and cemented, and the
flow may broach to the surface at a considerable distance from the wellbore, undetected.
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Structural support of platform is eroded.
It slides down and triples over
Structural support of csg is eroded.
It slides down and buckle
BOP
Weak cement
CSG
Weak zone
Water finds its way to the surface through weak cement
behind the casings and then through the weak zones
Weak cement
Unconsolidated sand is eroded and
produced before second csg is set
CSG
Figure 8-7: The SWF problem.
Shallow water flow is encountered in shallow formations below the mud line in deep water. The
zone’s overpressure is marginally larger than the hydrostatic pressure (usually in the 9.2 – 9.5 PPG
range), as indicated in Figure 8-8. Shallow flows are difficult or impossible to stop because of the
narrow margin between the pore pressure and the fracture pressure.
Origin of the weak over-pressured sand formations include induced storage during drilling through the
sand zone or geo-pressured sands, and transmission of pressure through cemented annulus (internal
channels in the cement). Geo-pressured sands originate from different mechanisms, the most likely
cause being rapid sedimentation of clay produced by large river systems.
Mud pressure (ECD)
Pore pressure
Shale
Sand zone
High pore pressure
Normal pore pressure
Sand being charged by mud;
gas or water flowing out
Sand zone inside a high
pressured shale
Figure 8-8: A small and permeable sand being charged by high ECD (left) or by geo-pressured shale (right).
One method suggested for estimation of SWF potential is as follows: Calculate the sedimentation rate
of the shallowest shale by seismic correlation to the shallowest available offset paleo-data. If the
sedimentation rate is less than 500 ft per million years at the planned drilling site, the sands should
have no significant pressure. If the rate has been higher than 500 ft. per million years, then treat the
sands (inside the shale) as potentially pressured. Once the geology in the area has been mapped, well
locations can eventually be adjusted to avoid SWF or casing programs can be modified.
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8.2.2. Shallow gas
The term Shallow Gas represents the problem of drilling through gas bearing shallow sands, and is
similar to SWF. Shallow gas implies free gas or gas in solution that exists in permeable formation which
is penetrated before the surface casing and BOP has been installed.
The most common method of offshore drilling up to 1987 was to apply a riser for drilling all sections,
and divert the gas through a gas diverter system on the rig, as shown in Figure 8-9.
Diverter (BOP)
Bend
Ball valve
Ball joint
Slip joint
Ball valve
Ball valve
Bend
Mud return
Riser
Ball joint
Figure 8-9: Gas diverter system.
After 1987 it became common to drill the two first well sections without a riser. The problematic
combination of riser – Shallow Gas became evident through many shallow gas blowouts, and especially
in 1986 when the Haltenbanken blowout was investigated and made public (NOU 1986). The floating
drilling rig West Vanguard was drilling outside Trøndelag on Haltenbanken when shallow gas blew out.
The well blew for almost five months before it depleted and could be cemented and plugged. This
incident will be presented in some detail because so much was learned from it. First, in Figure 8-10 the
situation just before, during and after the blowout is summarized together with comments made by the
investigation commission.
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20:00
Mud volume increases continously
→Loss of cuttings compensated
by adding water continously
Drill break in sand at 506 m
21:00
Mud pit indicator zeroed
21:35
Circulated 40 min. Max gas = 92 → stabilize
21:48
22:00
Connection. Gas content increases
E-log indicate gas sand 50 % sand in cuttings
Here it looks like lost circulation occurs
22:18
Gas increase. Circulated 30 min
Gas top 549
22:30
Mu
dg
c
as
on
ten
Down to 80 → stabilizes
Cnx. Serious return flow
Diverter activated
Pumped heavy mud. Gas flow and noice
Noice reduced Full alarm
Into boats. Gas, sand and mud blowing
40 m horizontally from diverter line
Disconnect riser. Explosion.
n
o
iti
re
s
u
People escape through in-door corridors
ss
po
ok
p re
Platform chief relesed 4 anchors. Plattform pulled forward, tilting 12 o
Ho
mp
Pu
Lifeboat 1 and 2 with 30 + 47 people. Platform and stability chief swam
22:52
23:00
23:10
23:15
23:20
t
e
tiv
Ac
pit
lev
el
Figure 8-10: Summary of the shallow gas blowout on Haltenbanken, October 6, 1985, with comments to the
mud log from investigators.
The investigation concluded by stating that the narrow pressure window was the root cause of the incident.
Evolution of the blowout is presented in Figure 8-11.
Depth (m)
Figure 8-11: Hypothesis of cause behind the blow out: Shallow sand was being charged by the ECD and later feeding
gas from it during connections.
Circulating out shallow gas through a diverting system is characterized by very high surface pressure
and high gas velocities. When the well started to blow, very soon afterwards, critical flow developed,
and the reservoir pressure minus friction loss was transferred to the surface. In such situations, it was
very understandable that the following situations took place:
- Surface pipes and pipe bends in the diverter system eroded. Sand production of the formation
caused severe sand blasting, especially in bends
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- The riser slip joint was stretched beyond its elastic limit and caused leakage
The only solution to this problem was to avoid the riser and drill riser-less, as shown in Figure 8-12.
Figure 8-12: Offshore drilling before (left) and after (right) 1986.
Some distinguished advantages were achieved:
The overall drilling operation became safer, mainly because the risk of explosion and fire risk on the rig
was very low. In addition, it was important that the stability was not influenced by sand production
through a broken diverter line any more. Experience and experiments showed that this probably affects
the stability more than gas percolating up under the floater!
The deeper the water depth, the more likely it is that, without a riser, a gas plume from the well will be
swept away from the vessel by the sea currents. When drilling top holes in deep-water, the relative
merits of riser-less drilling included additionally that time was saved due to fewer riser
running/pulling.
The all over control of the drilling operation was much lower than with a riser installed, but was
compensated for through proper procedures.
• Use video surveillance and wait for 15 minutes after each cnx
• Dynamic and/or weighted fluid kill procedures, including mixed mud, should be ready to
implement immediately. At least two hole-volumes of kill mud must be at hand.
• A small pilot-hole (9 7/8” or less) increases the capability of dynamic killing.
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When SWF or SG is detected, the well must be killed fast. Since the wellbore is open, it requires
special procedures. It also requires special precautions and mitigations:
8.2.3. Gas hydrates
The main reason behind the large amounts of offshore gas hydrates is low sea temperature.
Low offshore ocean temperature
At large sea depths the ocean can decrease below 0 oC, as shown in Figure 8-13.
Temperature (oC)
0
2
4
6
8
0
10
Geo-temperature onshore
Depth below sealevel (m)
-2
Relative depth (%)
Geo-temperature offshore
50
Annular mud temperature
70
100
Drill pipe mud temperature
0
50
70
100
Relative temperature (%)
Figure 8-13: Typical temperature profile in deep oceans (left). Generalized (right).
Mud will move slowly to the surface in the large marine risers and therefore be exposed to cooling. At
periods of still stand, the subsea BOP area is cooled down to the temperature of the sea. Low mud
temperature has two negative effects during oil well drilling:
- The possibility of hydrates formation
- Increased mud viscosity
Hydrate formation
Hydrates are a well-recognized operational hazard in deep-water drilling. Water is acting as host
molecules forming a lattice structure acting like a cage, to entrap guest molecules (gas) as shown in
Figure 8-14.
Figure 8-14: Gas hydrate: Dipolar water molecules are forming around a guest molecule (left). Water
molecules become hydrogen bonded (right), forming a hydrate crystal structure.
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Gas hydrates resemble dirty ice and can form in temperatures above 0 oC at simultaneously sufficient
pressure. They are solid in nature and have a tendency to adhere to metal surfaces. In deep water
environments the potential for hydrate formation increases due to the combination of higher pressure
and low temperature. Necessary conditions for hydrates to form are:
- Sufficient water
- Gas
- High pressure / Low temperature
Figure 8-15 shows the effect of pressure and temperature on hydrate formation. Methane is by far the
most common gas in oil well drilling. The points along this curve represent the temperature at which
the last hydrate melts or dissociates.
Pressure (bar)
200
Hydrate
formation
region
100
30
20
Increasing specific gravity of gas
Free gas
region
0
10
20
Temperatrue (oC)
Figure 8-15: Effect of temperature, pressure and gas composition on hydrate formation. Methane gas has
low specific gravity.
Potential Problems
The three types of hydrate-formation problems are as follows:
1.
2.
Natural gas is forming natural hydrates in the sedimentary formations at shallow depths below see
bottom. It is a challenge to drill through
Formation of hydrates inside the wellbore or BOP equipment, hindering control of BOP functions
and access to the wellbore during killing operations. Plugging in front of the choke/kill line causing
inability to circulate out a kick, or, hydrate plugs in the BOP cavities or just below the stack
resulting in an inability to circulate and to perform pressure monitoring
Usually hydrates do not form during routine drilling and/or circulating operations since the
combination of required conditions do not exist (mud is too warm during drilling). Hydrates usually
form when a gas kick is closed-in. Gas may now be caught and separated out below the BOP. During
an extended shut-in period where the gas cools rapidly, hydrates form in the BOP area.
Hydrate Inhibition
There are two common ways of inhibiting the drilling mud system to form hydrates:
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Thermodynamic inhibitors lower the activity level of the aqueous phase, thereby suppressing the
temperature required for hydrate stability at any given pressure. These are salts (CaCl2 and CaBr2),
methanol and glycol.
Kinetic inhibitors (or crystal modifiers) alter the nucleation and delay the growth of hydrates by using
a low concentration of polymeric and surfactant-based chemicals.
Hydrate Removal: Once hydrate plugs have formed in subsea equipment, their removal is problematic.
In one case, heated fluid was pumped down through a coiled tubing run inside the drill pipe to a depth
a few hundred feet below the hydrates eventually decomposing the hydrate.
8.3. Gas migration through cement
Cementing is critical due to loss of hydrostatic pressure in the cement slurry during its hydration
phases. During the transition period when hydrostatic pressure of the slurry is decreasing below water
pressure, the slurry strength is low, porosity and permeability is high, and, unfortunately, gas may
enter the weak cement and find its way through it, or, through a micro annulus which is caused by
shrinkage. The phenomenon is referred to as Gas migration through cement (GM).
First, we give a short summary of cement chemistry and point out some important factors that have
influence on gas migration.
8.3.1. Composition & hydration of cement slurries
Table 8-4 presents the important components in the cement manufacturing process.
Table 8-4: Raw material components in cement powder production. Slurry is made by mixing cement powder
and water. For Portland cement the water-to-cement ratio, w/c = 0.4 (40 % water bwoc).
Raw material
Lime
Clay
Aluminum oxide
Mangan oxide
Iron oxide
Gypsum
Important components
CaO
SiO2
Al2O3
MgO
Fe2O3
Ca SO4 2H2O
Symbol
C
S
A
F
Weight % in dry material
65
22
6
2
3
1-3
When the produced cement powder is mixed with water to make cement slurry, the reaction between
the two is exothermic, as presented in Figure 8-16. By recording the temperature evolution, it is
possible to follow the hydration process.
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Min
Hours
Days
30
60
70
90
97 (% hydrated)
8-16: Hydration of cement after mixing with water
In the upper part of Figure 8-15 we follow the development of two cement powder particles. A
resulting needle-like mineral called Etringite is growing out from each particle. After a “dormant”
period of typically 3-6 hours, the “initial set” state is reached; the needles are beginning to interfere
with neighbouring needles, and the fluid-like slurry begins to stiffen. Soon afterwards it is not possible
to pump it any more. At “final set” the cement is hard and not penetrable by a Vicat needle.
8.3.2. Laboratory testing of cement
•
consistency (test the pumpability)
contraction / shrinkage
free water
compressive and tensile strength
permeability
Porosity
y
nc
ist
e
co
ntr
ac
tio
n
ns
To
tal
•
•
•
•
•
co
But some are special for the cement slurry,
as indicated in Figure 8-17. The special ones are:
Temperature
rheo
logy
• density
• filter loss
• rheology
Parameter variation
The slurry needs to be tested in the laboratory, and many of the tests are similar to those applied on
drilling fluids parameters, like:
External shrinkage
time
Figure 8-17: Some of the cement parameters
measured in the laboratory.
All additives will reduce the strength of the hardened cement.
8.3.3. The GM problem
After the blowout in Gulf of Mexico in 2010 the topic of gas migration has become more relevant
again. Some of the material presented here is taken from the book by Nelson (2010) plus resent
papers.
Annular fluid migration also called gas communication, gas leakage, annular gas flow, gas
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channelling, flow after cementing, or gas invasion, may occur during drilling or during well
completion, and has long been recognized as one of the most troublesome problems of the petroleum
industry. It materializes it selves as an invasion of formation gas into the annulus, partly because of a
pressure imbalance at the formation face. The severity of the problem ranges from the most hazardous,
e.g., a blowout situation when well control is lost to the most marginal, e.g., a gas pressure of a few psi
in one or more annuli at the wellhead.
Pressure (psi)
S
h hri
w yd r n ka
at . p g
er . e
p. fal sta
ls rt
be s,
lo
w
p.
W
at
er
P
co u m
m pi
pl ng
et
ed
Sl
kl urr
hy ing y i
dr ing s g
. p , el
. t tra lin
o ns g
w fe an
al rr d
l
in
g
Gas migration occurs even when the annular fluid densities are such that the initial hydrostatic head is
much higher than the pore pressure. Hydrostatic pressure reduction during cement hydration has
previously been demonstrated in the laboratory, and confirmed by field measurements performed by
Exxon in 1982. The use of external casing sensors permitted the observation of downhole temperature
and pressure as shown in Figure 8-18.
4000
7000 ft
3000
6000
Temperature (0 F)
2000
225
205
175
6000
7000
Shrinkage starts
145
0
5
10
15
(hours)
Figure 8-18: Annular pressure and temperature measurements from external sensors (Exxon, 1982).
Laboratory measurements in a vertical pipe with no external pressure source demonstrated that the
hydrostatic pressure gradient gradually decreases to that of the pore water as shown in Figure 8-18.
Later, when the hydration accelerates, the hydrostatic pressure reduces below the pore pressure. The
hydrostatic pressure reduction is the result of shrinkage within the cement matrix due to hydration and
fluid loss.
The concept of transition state was introduced, an intermediate period during which the cement
behaves neither as a fluid nor as a solid, and the slurry loses its ability to transmit hydrostatic pressure.
The concept of transition state was quantified by a transition time, starting with the first gel strength
increase, and ending when gas could no longer percolate within the gelled cement. Here follow more
details of this possible explanation:
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T
6
ctio
n
5
4
Tota
l co
ntra
Volume reduction (%)
Temperature (-)
Cement hydration is responsible for an absolute volume reduction of the cement matrix. The shrinkage
is well documented in the civil engineering literature and occurs because the volume of the hydrated
phases is less than that of the initial reactants. Chemical contraction is split between a bulk or external
volumetric shrinkage, less than 1%, and a matrix internal contraction representing around 5 % by
volume of cement slurry, as exemplified in Figure 8-19.
3
2
1
External shrinkage
0
time
Figure 8-19: Typical contraction and external shrinkage
8.3.4. Gas migration routes
Formation gas is flowing up to the surface through three different routes, shown in Figure 8-20.
Cement
Casing
Figure 8-20: Three routes of the cement; through pore structure (left), along weak bonds (micro annulus),
and, through cracks developed at a later stage.
Through the cement pore structure
Before the cement slurry sets, the interstitial water is mobile; therefore, some degree of fluid loss
always occurs when the annular hydrostatic pressure exceeds that of the formation. The process slows
down when a low-permeability filter cake forms against the formation wall. The volume change
within the hydrating cement will provoke a sharp pore-pressure decline; consequently, gas percolation
can be considered as a particular type of gas migration, where gas in the form of macroscopic bubbles
invades the slurry and rises due to buoyancy effects in accordance with Stokes’ Law.
Along weak bonds
Regardless of the cement system, gas can still migrate along the cement/formation or cement/casing
interface if micro annuli have developed or along paths of weakness where the bond strength is
reduced. Good bonding is the principal goal of primary cementing.
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It has been found that cement shrinkage by itself probably does not lead to the development of a
microannuli, but instead to the development of reduced surface bound. Thus, the development of a true
microannuli could only be due to an additional stress imbalance between one of the two considered
interfaces due to excessive downhole thermal stresses, hydraulic stresses and, mechanical stresses.
After cement setting
After setting, during the hardening phase, normal density cement becomes a solid of very low
permeability, at the micro Darcy level. However, it should be noted that low-density cement systems
with high water-to-cement ratios can exhibit fairly high permeabilities (0.5 to 5.0 mD). Cracks
developed by the same forces behind weakened bonds may largely increase the permeability after
cement setting. Therefore, it is possible for gas to flow, albeit at low rates, within the matrix of such
cement, and to eventually reach the surface. Such events may take weeks or months to manifest
themselves as measurable phenomena at the surface, where they usually appear as slow pressure
buildups in the shut-in annulus.
8.3.5. Solutions to GM
Over the years, a number of methods to control gas migration have been proposed. The basic “good
cementing practices” is a prerequisite for controlling gas migration. This includes mud and mud cake
removal
- Rotate/reciprocate during displacement to avoid fingering and unobtainable surfaces. Use
scrapers and centralizers
- Flow rate maximum => flat flow profile results in improved sweeping
- Low fluid loss and free water, especially in deviated wells have been identified as
promoting the occurrence of gas migration. To minimize the impact of these parameters
on gas flow, both must be reduced to fairly low levels.
The most popular techniques to minimize gas migration that have been applied are listed below.
Compressible Cements
Expansive Cements
“Right-Angle-Set” (RAS) Cements
Impermeable Cements
Elastic Cements
In recent years the focus has been on elastic cement systems. Elastic additives have very low Young’s
modules, and provide resilient, non-foamed cement that isolate wellbores cemented across gas sands.
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9. References
Bellarby, J. (2009): Well Completion Design. 1st edition. Elsevier, Amsterdam
Bourgoyne, A.T., Jr., Chenevert, M.E., Millheim, K.K. & Young, F.S., Jr.: (1991). Applied Drilling Engineering. SPE Textbook
Series, Vol. 2, 3rd edition, Society of Petroleum Engineers, Richardson
Basmadjian, D. (2003): Mathematical Modeling of Physical System. Oxford University Press, New York
Brechan, B. (2015): Drilling operations, Chapter 17. Compendium at IGP, NTNU, Trondhiem
Casson, N. (1959): "A Flow Equation for Pigment-Oil Suspensions of the Printing Ink Type", Rheology of Disperse Systems,
Pergamon Press, New York, N.Y.
Chilingarian, G.V. and Vorabutr, P. (1983): Drilling and Drilling Fluids, Elsevier Science Publishers, Amsterdam, Updated
first edition
Classifications of fluids systems. (2017): World Oil
Darley, H.C.H. and Gray, G.R. (1991): Composition and properties of drilling and completion fluids. Gulf publishing
company, Pittsburg, fift edition, second printing
Drilling Data Handbook (2015). Edited by IFP (Institute France du Petrol) and published by Edition Technip, Paris
Drilling fluid engineering manual (1982): Magcobar Division of Dresser Industries Inc., Houston
Drilling service companies:
Geosevices http://www.geoservices.com/
Halliburton M-I Swaco Schlumberger -
http://www.halliburton.com/
http://www.miswaco.com/ (now (2013) a SLB company)
http://www.slb.com/
Economides, M., Oligney, R. and Valco, P. (2002): Unified Fracture Design. Orsa Press, Alvin, Texas
Economides, M., Watters, L. and Dunn-Norman, S., 1998: Petroleum Well Construction, John Wiley & Sons, Chichester
Google as dictionary; http://www.google.no/language-tool/
Govier, G.W. and Aziz, K. (1972): The Flow of Complex Mixtures in Pipes. E. Krieger Publishing Co., Malabar, Florida
Hale, a. H., Mody, F. K. and Salisbury, D. P. (1993): The influence of chemical potential on wellbore stability. SPEDC; Sep.
Holman, J. P. (2001): Heat Transfer. Eight SI Metric Edition, McGraw Hill. Singapore
Kutasov, I.M. (1991): Correlation simplifies obtaining downhole brine density. Oil & Gas J. (Aug. 5) 48-49.
Mitchlll, R. F. (1988): Dynamic surge / swab pressure predictions. SPEDE. September. 325-333.
van Oort, E. (1997): Physico-chemical stabilization of shale. SPE paper 37 263, presented at the SPE International Symp. on
Oilfield Chem., Houston, 18-21 Feb.
White, F. M. (1999): Fluid Mechanics. International Edition, WCB/McGraw-Hill, Singapore
Wikipedia as encyclopaedia in 250 languages; http://en.wikipedia.org/
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Garnier et.al. (2010) Garnier, A., Saint-Marc, J., Bois, A. P. and Kermanac’h, Y.: “An innovative methodology for designing
cement-sheath integrity exposed to steam stimulation”, SPED&C, March 2010, 58 – 69.
Nagelhout at al. (2010)Nagelhout, A. C. G. at. al.: “Laboratory and field validation of a sealant system for critical plug - and
– abandon situations”, SPED&C, Sept. 2010, 314-321
Niznik, M. R., Lawrence, A. and Zeilinger, S.: Drilling highly depleted formations with engineered particles non-aqueous fluids
(EP-NAF): South China Sea. SPE paper 139 932, presented at the SPE / IADC Drilling Conf. & Exhib., Amsterdam, 1-3 March,
2011.
Petrucci, R.H.: "General Chemistry", 5.edition, Macmillan Publishing Co., New York (1989).
Reddy at.al. (2010) Reddy, B. R., Liang, F. and Fitzgerald, R.: “Self – Healing cements that heal without dependence on fluid
contact: A laboratory study, SPED&C, Sept. 2010, 309-313.
Rehm, B. et al.: UBD, Limits & Extremes. Gulf Publishing Co., Houston, 2007.
Skalle, P., Podio, A.L. and Tronvoll, J. (1991): Experimental Study of Gas Rise Velocity and tis Effect on Bottomhole Pressure
in a Vertical Well”, presented at the Offshore Europe Conference, Aberdeen, 3-6 September
Skalle, P. (2012): Drilling Fluid Engineering, www.BoonBook.com,
Skalle, P., Aamodt, A. and Gundersen, O. E. (2013): Detection of symptoms for revealing cuses leading to drilling failures.
SPEDC June
Thomas, G.B., Jr. (1973): Calculus & analytic geometry. Addison & Wesley Publ. Co, Pittsburg
van Oort, E., Friedheim, J., Pierce, T. and Lee, J. (2011): Avoiding losses in depleted and weak zones by constantly
strengthening wellbores. SPEDC Dec.
West Vanguard-rapporten; Uncontrolled blowout on drilling platform West Vanguard 6. October 1985, Norges Offentlige
Utredninger, NOU 1986:16.
Tuttle, R. N. and Barkman. J. H. (2000): New Non-damaging and Acid-Degradable Drilling and Completion Fluids
Bellarby, J. (2009): Well Completion Design. 1st Edition
Aadnoy, B., Cooper, I., Miska, S., Mitchell, R. F. and Payne, M. L. (2013): Advanced Drilling and Well technology, SPE,
Richardson,
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10. Symbols
Latin:
A
Aw
a
b
B
C
Cap
d, D
D
c
d
E
f
FCP
G
g
h, H
h
ICP
K
KL
k
k
l, L
m
M
M
MAASP
N
n
p, P
P
Dp
q
q
Q
r
R
R
R
R
R
SCR
SICP
T
t
V
x,y,z
z
Ø
w
w
W
Cross sectional area
Water activity
Constant
Constant
Buoyancy
Concentration
Volumetric capacity
Diameter
Depth
Concentration of volume fraction of particles
Diameter
Modulus of Elasticity
Fraction
Final Circulating Pressure
Gradient
Acceleration due to gravity
Height, depth
Heat transfer coefficient
Initial Circulating Pressure
Power law consistency index
Coefficient for bit pressure loss
Constant
Thermal conduction coefficient
Length
Mass
Frictional torsion momentum at lower end of pipe
Molecular Weight or mol number
Maximum annular allowable surface pressure
Number
Exponent in power law (flow behaviour index)
Pressure
Power
Pressure change
Volumetric flow rate
Heat rate
Heat flow
Radial position
Radius of pipe
Universal gas constant = 8.31447
Gas Liquid Ratio (at standard conditions)
Thermal heat resistance
Electrical resistance
Slow Circulating Rate
Shut in casing pressure
Temperature
Time
Volume
Cartesian coordinates
Vertical depth
Porosity
Width
Unit weight of pipe
Weight
m2
m3/m
m
m
Pa
Pa/m
m/s2
m
W/(m2 . 0C)
Pa
Pasn
W/(m . 0C)
m
kg
mol
Pa
W
Pa
m3/s
W/m2
W
m
m
J/ (0K⋅mol)
m3/m3
ohm
m3/s
0
K
s or s
m3
m
m
- or %
m
N/m
122
Compendium of ADC
Greek:
a
Azimuth angel at lower end of element
𝛼
𝛼2 +𝛼1
b
b

D
DF
Da
Db






r



Inclination angel at lower end of element
Constant
hickness
Difference, change
Increase in tensile force over length of element
Increase in azimuth angel over length of element = 𝛼2 − 𝛼1
Increase in azimuth angel over length of element = 𝛽2 − 𝛽1
Extension, strain
Shear rate
Viscosity
Sliding friction coefficient between drillstring and wellbore
Poisson’s Ratio
3.1416
Mass density
Surface tension; Axial stress
Shear stress
Cylindrical coordinate (rad), readings in Fann viscometer
2
, average angle between two stations
m
-
m
s-1
Pas
kg / m3
Pa
Pa
-
Subscripts (abbreviated) referring to:
a, ann
app
bit
c
csg
cs
dp
eff
F
fl
fm
frac
f
g
i
i, j
liq
LO
M
max
N
ovb
pl
r
Re
S
t
tot
w
y
x,y,z
E, Z, N
0
0,1,2
annulus
apparent
drill bit
circulating, corrected, capillary
casing
casing shoe
drill pipe
effective
Fanning
fluid, flow line
formation
fracture
friction
gas
initial, inner
counter
liquid
leak off
mean
maximum
normal
overburden
plastic
radial position
Reynolds number
surface, standard conditions
tension
total
water, wall
yield
Cartesian axis
Direction; East, Vertical and North
value at start point
value at situation 0, 1 or 2
123