Introduction to WC

1. Hydrostatic Pressure
Intro to well control

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Hydrostatic
pressure
Hydro = fluid
Static = at rest
Hydrostatic pressure:
• The pressure exerted by a
column of fluid at rest.
• The hydrostatic pressure is
found by multiplying the weight
of the fluid by the height of the
fluid column.

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DEPTH
PRESSURE
Gradient formation fluid = 0.465psi/ ft - 0.1051 Bar/m
Hydrostatic
pressure

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DEPTH
PRESSURE
Gradient SW = 0.465psi/ ft - 0.1051 Bar/m
The shape and the size of the
hole does not matter to the
bottom hole pressure. Only the
true vertical height (TVD)of the
fluid collum
Hydrostatic
pressure

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DEPTH
PRESSURE
0.1051 bar/m
500m
1000m
500m x 0.1051bar/m = 52.5 bar
1000m x 0.1051bar/m = 105 bar
Hydrostatic
pressure

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DEPTH
PRESSURE
0.465 psi/ft
1500´
3000ft
1500ft x 0.465 psi/ft = 697.5psi
3000ft x 0.465 psi/ft = 1395 psi
Hydrostatic
pressure

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P = MW x TVD x k
Here we say:
Pressure in PSI = mud weight in PPG x depth in FT
To make that happened, we will need a factor to convert
ppg and ft to psi
The conversion factor “k” is 0.052 and have the unit
PSI/FT
Hydro- means a fluid
Static- means at rest
Hydrostatic in the wellbore is from the mud
Hydrostatic pressure

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Further:
Mud weight in PPG x 0.052 = Pressure gradient [psi/ft]
What is the theory behind all this:
Hydrostatic Pressure is the pressure exerted by a column of
fluid at rest, and is calculated by multiplying the gradient of
the fluid by the True Vertical Depth at which the pressure is
being measured:
Hydrostatic pressure [psi] = Fluid gradient [psi/ft] x TVD [ft]
Hydrostatic pressure

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DEPTH
0
2500
5000
1000 2000 3000 4000 5000
PRESSURE
1 Gas grad. 0.07 psi/ft
2 Oil grad. 0.30 psi/ft
3 Fresh W. grad 0.433 psi/ft
4 Salt W. grad 0.465 psi/ft
5 10 ppg grad. 0.52 psi/ft
6 15 ppg grad. 0.7785 psi/ft
7 21 ppg grad. 1.091 psi/ft

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is the fluid pressure in the pore spaces of
the formation.
Formation Pressure
PSI
Normal Formation Pressure
Gradient = 0.465 psi/ft

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is equal to the hydrostatic pressure of the water occupying the
pore spaces from the surface to the subsurface formation.
Native fluid is mainly dependent on its salinity and is often
considered to be: 0.465 psi/ft
Normal Formation Pressure

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PRESSURE
DEPTH
NORMAL PRESSURE
0.465 PSI/FT
ABNORMAL
PRESSURE
SUBNORMAL
PRESSURE

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Formation Pressure
Formation Pressure
Depth
Normal Pf
Abnormal Pf
Subnormal Pf

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1
2
3
4
5
6
7
8
9
10
11
0.4 0.5 0.6 0.7 0.8 0.9 1.0
PSI/FT
26”
18-5/8”
13-3/8”
9-5/8”
PORE
&
FRACTURE
Fracture Pressure
Pressure at
which the
formation will
start to break
down.

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The function of well control can be subdivided into 3 main categories:
• Primary Well Control:
The use of the fluid to prevent the influx of formation fluid into the well
bore MUD.
So What’s the need to monitor the mud parameters including:
 Mud density
 Mud Flow
 Pit levels
• Secondary Well Control:
The use of the BOP to control the well if Primary WC can not be maintained
EQUIPMENT
• Tertiary Well Control:
Relief well HELP!
Principles & Procedures

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Principles of Well Control
Balance
Hydrostatic Pressure is equal to
Formation Pressure

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Over-Balance
Hydrostatic Pressure is greater than
Formation Pressure
Principles of Well Control

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Under-Balance
Hydrostatic Pressure is less than
Formation Pressure
Principles of Well Control

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Primary control
PSI
PSI
FORMATION FLUID
PRESSURE
MUD
HYDROSTATIC
5000
4800
MUD HYDROSTATIC
IN WELLBORE
Mud Hydrostatic pressure prevent formation fluids entering the well bore

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It is an influx of formation fluid into the wellbore that causes the well
to flow
What Is A Kick?

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An Uncontrolled exit of the formation fluids at the surface
What Is A Blowout?

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Secondary Control

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Blowout Preventers (BOP)
Annular
Ram
Side outlet
valves
Control
Hoses
Choke &
Kill lines

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Subsea Factor and Complications vs. Surface
The difference between subsea and surface drilling
operations can be described in the following aspects:
• Vessel Movement and weather (Emergency disconnect)
• BOP on sea bed, redundancy and configurations
• Water depth
• Riser above BOP (Gas expansion)
• Choke and kill line lengths and contents

25. Calculations
Intro to well control

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a
=
A 2
Areas
b
x
a
=
A
2
h
x
a
=
A
Area of a square
Area of a rectangle
Area of a triangle

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R
x
=
A 2

Area of a circle
4
D
x
=
A
2

360
x
R
x
=
A
2


Area of a sector of a circle
Areas

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)
f
-
(R
x
2
DF
-
360
x
R
x
=
A
2


Area of a segment of a circle
)
r
-
R
(
x
=
A 2
2

Annular area or cross sectional area of hollow cylinder
4
)
d
-
D
(
x
=
A
2
2

Areas

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Annular Areas
PUMP
Casing 18-5/8” 87.5 lb/ft N80
DP 5” S-135
Pressure test 500 psi
Pressure Testing / Upward Pressure

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Areas
Pressure Testing 18-3/4” BOP shear ram to 15000 psi on the Stump.
Do the math......

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Volume, Capacity and Displacement
h
R
A
D
Area of a circle
R
x
=
A 2

4
D
x
=
A
2

or
Volume of a cylinder
h
x
A
=
V
4
h
x
D
x
=
V
2

or

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h
R
A
D
Volume in ft3 of a 1 ft high cylinder when the diameter D is given in inches (in)
]
ft
[
12
x
4
1
x
D
x
=
V 3
2
2

Volume in bbl of a 1 ft high right cylinder when the diameter D is given in inches (in)
]
bbl
[
5.6146
x
12
x
4
1
x
D
x
=
V 2
2

]
bbl/ft
[
1029.4
D
=
V
2
Internal Capacity

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D
d
H
4
H
x
)
d
-
D
(
x
=
V
2
2

Volume in bbl of a 1 ft high right cylinder when the diameters D and d is given in inches (in)
]
bbl/ft
[
5.6146
x
x
4
H
x
)
d
-
D
(
x
=
V
2
2
144

]
bbl/ft
[
1029.4
)
d
-
D
(
=
V
2
2
Annular Capacity

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1 ft
Metal Displacement
Weight of metal @ 7.85 kg/l 65.44 lbs/gal
65.44 lbs/gal x 42 = 2748 lbs/bbl 2745 lbs/bbl
Weight (lbs/ft) = Displacement bbl/ft x 2745 lbs/bbl
Weight lbs/ft
Displacement = --------------------- = bbl/ft
2745 lbs/bbl

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Pump Displacement
]
bbl/stroke
[
1029.4
l
x
D
x
n
=
V
2
n = number of cylinders
D = Inside diameter of the cylinder liner in inches
l = length of stroke in ft
]
bbl/stroke
[
12352.8
x
l
x
D
x
n
=
V
2

n = number of cylinders
D = Inside diameter of the cylinder liner in inches
l = length of stroke in inches
ŋ= dimensionless factor representing the volumetric efficiency
]
bbl/stroke
[
x
l
x
D
=
V
2
65
,
4117


36. Barrier Concept
Intro to well control

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Norsok Standard D-010 - Terminology
3.1.38 Primary well barrier
First well barrier that prevents flow from a potential source of inflow.
3.1.47 Secondary well barrier
Second well barrier that prevents flow from a potential source of inflow
3.1.62 Well barrier
Envelope of one or several well barrier elements preventing fluids from flowing
unintentionally from the formation into the well bore, into another formation or to the
external environment.
3.1.63 Well barrier element
A physical element which in itself does not prevent flow but in combination with other
WBE’s forms a well barrier
3.1.60 Ultimate well barrier stage
Final stage of a well barrier element activation sequence which normally includes closing
a shearing device.
Well Barriers

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Well Barriers
• A barrier has the intention to reduce or avoid the consequence of an
unwanted situation or accident. This includes both technical (ie: Bridge Plug
which maybe the current Active barrier) human and organizational
barriers (ie: Procedures or Passive barriers)
• If we look at well barriers, it consists of one or several barrier elements
that form a continuous and protective envelope around the wellbore. Its
purpose is to prevent an uncontrolled and unintentionally gas or fluid flow
into another formation or to surface [2]
• The well barrier ensures the overall safety on board a platform and it also
prevents contamination of wellbore fluids into the environment. Should a
barrier or a barrier element however fail, actions to replace and reinstate
the failed barrier or barrier element should be number one priority, all other
well related activities should temporarily be stopped until the barrier or
barrier element is fixed and reinstated [4].

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API Standard 65-2 Terminology
3.1.7 Barrier (barrier element)
A component or practice that contributes to the total system reliability by preventing
liquid or gas flow if properly installed.
3.1.34 Mechanical barrier
A subset of physical barriers that features mechanical equipment, not set cement or a
hydrostatic column.
3.1.45 Physical barrier element
Physical barrier element can be classified as hydrostatic, mechanical or solidified
chemical materials. (usually cement)
Well Barriers

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API Standard 65-2 Terminology
4 Barriers
4.2 Physical Barrier Element
4.3 Hydrostatic Barrier Element- when monitored or maintained
4.4 Annular Mechanical Barrier Element
• Generally tested to maximum differential pressure, taking flow direction into
consideration.
• Plugs set as close as possible to source. (to allow density of fluid above to
provide same pressure as below.
Well Barriers

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Drilling Activities
Drilling shearable Norsok D-010 5.8.1
Well Barriers

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Drilling Activities
Non shearable DP Norsok D-010 5.8.2
Well Barriers

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Inflow test
Defined differential created by reducing pressure on the downstream
side of a Well Barrier or Well Barrier Element (the differential has to
higher than max exposure)
The test is performed for a reason:
ensure proper planning, including:
• How is it done in a safe manner?
• What is the success criteria?
• Maintain volume control whilst in displacement/bleed off mode especially the point of
going underbalance must be known.
• What is the fail criteria. Volume / Pressure?
• How can we determine where a potential leak come from- surface or equipment being
tested
• How do we recover in case of failure (leak or function)?
If pressure or volume do not meet expectations, the well must be shut in as quickly as possible
and situation evaluated as per plan.
Fluids in the well will give hydrostatic pressure. With height and weight the Pressure hydrostatic
can be calculated

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High level
Low level
Well Control Risk Management

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What can I do to be more effective at risk management?
The following tips draw on common failings in risk management and can help your
team perform better:
• Put real time and effort into risk assessment: identifying hazards, assessing risk level, and
considering good control measures. Remember that paperwork alone doesn’t control the risk
• Make sure you and other crew are trained and competent at conducting risk assessment.
• Always remember the hierarchy of controls. Are there better control measures that should be
raised with management?
• Encourage a positive attitude to risk management and risk assessment amongst your fellow
crew.
• It is human nature to cut-corners. We often think ‘it won’t happen to me’, but shortcuts in risk
management lead to many incidents, including a great many fatalities. A little extra time
spent on risk assessment can mean the difference between someone making it home to see
their family, or not.
Well Control Risk Management

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Well Control Training
Well Control training is required as a minimum for Essential crew on a regular
basis every 2 years
OGP are an important stakeholder and make Well Control training
recommendations to improve standards and competencies within the industry
which are currently being implemented into IWCF training syllabus.
One of OGP recommendations is that both technical and non technical
competencies (Human Factors) are included in future training requirements,
in combination with team based training.
Well Control Risk Management

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API 59 Recommended Practice - DRILLS
• Pit Drill
Simulated pit gain
• Trip Drill
Installation of the FOSV at the shoe during a trip
• Strip Drill
At an appropriate time. Close the annular, with DP in the
hole, with the desired pressure trapped, each crew
member is assigned a task. Enough pipe is stripped into
the hole to establish workability and crew to be proficient
in stripping operations

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Drills Continued ….
• Choke Drill
Similar to above, with BOP closed circulating down the string up
through the choke, accurately monitoring flow rates to the trip
tank, and to gain proficiency in choke operation. Especially
important for subsea operations.
• Diverter Drill
Should be performed by following a rig procedure for the correct
operation of the diverter for offshore rigs without the BOP stack
installed, and also for floating rigs with the Subsea BOP installed.

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