Petroleum drilling fundamentals

1. Petroleum Drilling
Fundamentals
Sigve Hamilton Aspelund

2. Introduction to Rig types and
Drill Component
Rig Selection and basic planning
steps
Types of wells
Types of rigs
Steps to drill oil or gas wells
The well construction team
Well costing
Communications and safety issues

3. Basic pore pressure and
fracture gradient estimation
Units and terminology and basic
definitions
Geo pressure and well design
consideration
Causes of overpressure
Pore pressure theory
Real time diagnostics of pore pressure
Overburden gradient estimation
Fracture gradient estimation
LOT analysis
Casing seat selection
Uncertainty analysis.

4. Designing the well
Translating the geological prognosis into a well design
Rig selection
Types of drilling rigs – onshore and offshore
Drilling equipment
The rotary system – conventional, top drive, rotary steerable
Automated rigs
Contractor selection
Casing and Cementing
Drilling muds and completion fluids; types and functions
Bits and specialised drilling equipment
Formation and well evaluation requirements:
Mud logging
Wireline and MWD/LWD logging
Case Study: Casing design including uncertainties in pressure and
rock strength
Case Study: Identification of potential drilling hazards

5. Drilling the well
Monitoring progress in drilling operations
The daily drilling report – what does it contain
and how do you read it?
Well control issues – why the drilling foreman
needs a certificate:
Mud control and testing
Casing and cementing operations
Things that can go wrong
Stuck pipe
Overpressures
Lost circulation
Kicks

6. Completing the well
Types of completions – what is their
function?
Completion fluids – why are they
different from drilling fluids?
Basic completion string equipment
and Xmas trees
Sand control equipment – from
screens to gravel packs
Perforation technology – equipment
and safety aspects

7. New technology & ideas
“Drilling the limit” how to improve and
save money
Expandable tubulars
Multi-lateral wells
Smart wells (Intelligent completions)

8. Youtube videos
Oil and gas drilling video
Oil rig 3D animation
Petroleum engineers
Drilling for oil in Algeria
Blow out preventer
Well logging
Drilling, cementing and stimulation
3D seismic

9. Structural geology 1
Structural geology 2

10. Rig Selection and basic planning
steps
Offshore drilling
◦ Ca. 25% of worlds oil and gas is produced
from offshore fields (i.e. North Sea or Gulf
of Mexico)
◦ North sea: Exploration wells are drilled
with Jack up or Semi-submersible drilling
rigs.

11. Jack up
Retractable legs that can be lowered
to the sea bed. The legs support the
drilling rig and keep the rig in position.

12. Jack up
Unaffected by the weather during the drilling
phase
The safety valve is located on deck
It does not need anchoring system
It does not need heave compensator
(permanent installation in the drilling phase)
It has removable drill tower
Depth limit is 150 meters
It is unstable under the relocation
It depends on the tug for moving

13. Semi submersible
Portable device that consists of a deck
placed on columns attached to two or
more pontoons.
During operation tubes are filled with
water and lowered beneath the sea
surface.

14. Semi submersible
The vessel normally kept in position
by anchors, but may also have
dynamic positioning equipment (DP).
Usually have their own propulsion
machinery (max. depth approx. 600
to 800 meters).
The most common type is the "semi-submersible
drilling rig".

15. Drilling ship
In very deep water (2300m) drill ships
are used for drilling the well.
A drillship is easy to move
and is therefore well suited for
drilling in deep waters, since it is
well suited for
dynamic positioning. It requires relativ
ely little force to remain in position.

16. Condeep platform
Condeep platform is the denomination of a series
of oil platforms that were developed in Norway to drill
for oil and gas in the North Sea. The name comes
from
the English“concrete deep water structure", or deep
structure of concrete.
The platforms rest on thick concrete tanks that are on
the ocean floor and acts as an oil stock. From
these sticks it as one, three or
four slender hollow columns, which is about 30 feet
above the surface.

17. Condeep platform
It was Stavanger company Norwegian
Contractors who developed the concept of
Condeep platforms in 1973, after the success of the
concrete tank at the Ekofisk field.
Condeep platforms are not produced anymore. The
large concrete platforms are out competed by new,
cheaper floating rigs and remote-controlled
underwater installations.

18. Jacket platform
The most widely used platform in the North Sea
bearing structure is built as framed in steel
Platform are poles fixed to the bottom
The construction is susceptible to corrosion
Has no storage tank, but must be associated pipeline
network.

19. Tension leg platform
A tension leg platform is a floating and vertically
anchored platform or buoy which is normally used
for offshore production of oil or natural gas, and is
especially suitable for water depths exceeding
300 meters. We usually use rods or chains to keep
the platform in place.

20. Tension leg platform
Affordable solution
Quick to install
Can be equipped entirely by countries
Can be used on very deep
Can be moved when a field is empty
Because of movement of water required
compensation equipment

21. Well head plattform
Can be an alternative to production facilities on the
seabed, especially where water depth is small, as
in the southern part of the north sea. The
wellhead platform is an unmanned small platform,
which we can remotely control from a “mother
platform".
Valve tree is dry.

22. Exploration and production
licences
Government invite companies to apply
for exploration and production licences
on the continental shelf.
Exploration licences may be awarded
any time.
Production licences are awarded at
specific discrete intervals known as
licensing rounds.

23. Exploration, development and
abandonment
Before drilling an exploration well an
oil company will have to obtain a
production licence.
Prior to applying for a production
licence
◦ Exploration geologists
Scouting exercise
Analyse seismic data
Analyse regional geology
Analyse well tests in the vicinity of the prospect they
are considering

24. Explorationists
◦ Consider exploration and development
costs
Oil price and tax regimes
Establish if reservoir is worth developing
If prospect is considered worth
exploring
◦ The company will try to aquire a
production licence
Explore the field
The licence will allow company to drill
exploration wells in the area of
interest.

25. Before exploration wells are drilled
◦ Licencee may shoot extra seismic lines in
a closer grid pattern
Detailed information about the prospect
Assist in definition of optimum drilling target
Despite improvements in seismic
techniques the only way of
confirmining the presence of
hydrocarbons is to drill an exploration
well.

26. Drilling is very expensice
◦ If hydrocarbons are not found there is no
return on the investment, although
valuable geological information may be
obtained.
◦ With only limited information available a
large risk is involved.
Having decided to go ahead and drill
an exploration well proposal is
prepared.

27. The objectives of this well will be:
◦ to determine the presence of
hydrocarbons
◦ to provide geological data (cores, logs) for
evaluation
◦ to flow test the well to determine its
production potential, and obtain flud
samples.

28. The life of an oil or gas field can be
sub-divided into the following phases:
◦ Exploration
◦ Appraisal
◦ Development
◦ Maintenance
◦ Abandonment

30. The length of the exploration phase will
depend on the success or otherwise of the
exploration wells.
There may be a single exploration well or
many exploration wells drilled on a prospect.
If an economically attractive discovery is
made on the prospect then the company
enters the appraisal phase of the life of the
field.
During this phase more seismic lines may be
shot and more wells will be drilled to establish
the lateral and vertical extent of (to delineate)
the reservoir.

31. These appraisal wells will yield further
information, on the basis of which future
plans will be based.
The information provided by the
appraisal wells will be combined with all
of the previously collected data and
engineers will investigate the most cost
effective manner in which to develop the
field.
If the prospect is economical attractive a
Field development plan wil be submitted
to secrectary state of energy.

32. If approval for the development is
received then the company will
comeence drilling development wells
and constructing the production
facilities according to the development
plan.
Once the field is on-stream the
companies commitment continues in
the form of maintenance of both the
wells and the production facilities.

33. After many years of production it may be
found that the fild is yielding more or possibly
less hydrocarbons than initially anticipated at
the development planning stage and the
company may undertake further appraisal
and subsequent drilling in the field.
At some point in the life of the field the costs
of production will exceed the revenue from
the field and the field will be abandoned. All
of the wells will be plugged and the surface
facilities will have to be removed in a safe
and environmentally acceptable fashion.

34. Well planning and design

43. Standard Spiral drill collar

44. Integral heavy weight drill pipe and
Spiral integral heavy weight drill pipe
Square kelly

45. Pup joint
Stabilize
r
Cross over
sub

46. Integral heavy weight drill pipe Spiral drill collar

47. Super high pressure tubinTgu bing used for high-pressure
boiler

48. Drill Pipe
Applicable to API standard.
Steel grade EGXS. Size: 2 3/8 ，3 1/2，2 7/8，4 1/2，5，5
1/2.

49. Drill Collar
Collar
Applicable to API standard. Out dia：2 3/8”，3 1/2”，2 7/8”，4 1/2”，5”，5
1/2”.

50. Kelly
Kelly
Applicable API standard.Hex and square, two models.Size:3 1/2”，4 1/4”，5
1/4”，6”.

51. Heavy Weight Drill Pipe
Pipe Applicable API standard. Size: 3 1/2”，4 1/2”，5”，5
1/2”.

52. Tubing
Applicable to API standard.
Steel grade:J55,N80,P110. Size: 2 3/8”，2 7/8”，3 1/2”

53. Casing
Casing
Applicable to API standard.
Size: 4 1/2”，5 1/2”，7”，9 5/8”，10 3/4”，13 3/8”

54. Oil–Gas Delivery Pipes
Pipes
Applicable to API standard.
Size: 8 3/4”，10 3/4”，12 3/4”，14”，16”，18”，20”，22”
，24”，26”，28”，30”，32”，36”，40”，44”，48”，52”，
56”

55. Drill Bit
PDC bit
Cone bit

56. Drilling personnel
Drilling a well requires many skills and
involves many companies

57. The oil company who manages the
drilling and/or production operations is
known as the operator.
In joint ventures one company acts as
operator on behalf of the other
partners.
The oil company normally employ a
drilling contractor to drill the well.
Drilling contractor owns and maintains
the drilling rig and employs and trains
the personnel required to operate the
rig.

58. During the course of drilling the well
certain skills or equipment may be
required (e.g. Logging, surveying).
These are provided by service
companies.
These service companies develop and
maintain specialist tools and staff and
hire them out to the operator,
generally on a day rate basis.

59. The operator will generally have a
representative on the rig called the
company man to ensure drilling
operations go ahead as planned,
make decisions affecting progress of
the well, and organise supplies of
equipment. He will be in daily contac
with his drilling superintendent who
will be based in the head office of the
operator.

60. There may also be an oil company
drilling engineer and/or a geologist on
the rig.
The drilling contractor will employ a
toolpusher to be in overall charge of
the rig.
He is responsible for all rig floor
activities and liases with the company
man to ensure progress is satisfactory.

61. The manual activities associates with
drilling the well are conducted by the
drilling crew. Since drilling continues 24
hours a day, there are usually 2 drilling
crews.
Each crew workd under the direction of
the driller. The crew will generally
consist of a derrickman (who also tends
the pumps while drilling), 3 roughnecks
(working on rig floor), plus a mechanic,
an electrician, a crane operator and
roustabouts (general labourers).

62. Service company personnel are
transported to the rig as and when
required. Sometimes they are on the
rig for the entire well (e.g mud
engineer) or only for a few days during
particular operations (e.g. directional
drilling engineer)

63. Drilling economics
Drilling costs in field development
Drilling costs ~25-35% of total
development costs for an offshore
oilfield.

64. The costs of the development will not
be recovered for some time since in
most cases production is delayed until
the first few platform wells are drilled.
These delays can have a serious
impact on the economic feasibility of
the development and operators are
anxious to reduce the lead time to a
minimum.

65. Drilling cost estimates
Before a drilling programme is
approved it must contain an estimate
of the overall costs involved.
When drilling in a completely new
area with no previous drilling data
available the well cost can only be a
rough approximation.
In most cases some prevours well
data is available and a reasonable
approximation can be made.

66. A typical cost distribution for a North
Sea Well

67. Some costs are related to time and are
therefore called time-related costs (e.g.
Drilling contract, transport,
accomodation).
Many of the consumable items (e.g.
casing, cement) are related to depth and
are therefore often called depth-related
costs.
These costs can be estimated from the
drilling programme, which gives the
length or volumes required.

68. These costs can be estimated from
the drilling programme, which gives
the lenghts or volumes required.
Some of the consumable items such
as the well head will be a fixed cost.
The specialised services (e.g.
perforating) will be a charged for on
the basis of a service contract which
will have been agreed before the
service is provided.

69. The price list associated with this
contract will be a function of both time
and depth and the payment for the
service will be made when the
operation has been completed.
For wells drilled from the same rig
under similar conditions (e.g. platform
drilling) the main factor in determining
the cost is the depth, and hence the
number of days the well is expected to
take.

70. Plot of depth
against days for
wells drilled from
a North Sea
plattform.

71. Time breakdown
for a North Sea
well.

72. More sophisticated methods of
estimating well costs are available
through specially designed computer
programmes.
Whatever method is used to produce a
total cost some allowance must be made
for unforseen problems.
When the estimate has been worked out
it is submitted to the company
management for approval. This is usually
known as an AFE (authority for
expenditure).

73. Funds are then made available to
finance the drilling of the well withing a
certain budget.
When a well exceeds its allocated
funds a supplementary AFE must be
raised to cover the extra costs.

74. Communications and safety
issues
The Piper Alpha Disaster
In 1988 Britain suffered one of the
worst industrial disasters when the
Piper Alpha oil Platform was
destroyed by fire and gas
explosion, resulting in 167
fatalities. The disaster caused
significant changes to the manner
in which safety was regulated and
managed in the UK offshore oil
industry.

75. Events in the disaster
The Piper Alpha platform was operated by Occidental
Petroleum (Caledonia) Ltd. and located 110 miles
notheast of Aberdeen
The platform produced oil and gas and was linked to
the installations Tartan, Claymore and MCP01 by
subsea pipelines
On July 6, 1988, dayshift workers had removed a safety
release for a consendate pump that was not being used
and replaced it with a blank flange
Several hours later the night shift operations team
experienced a problem with a second consendate pump
and restarted the first pump, unaware of the the safety
valve had been removed

76. Around 10:00 pm there was an explosion on the
production deck of the platform which was caused the
ignition of a cloud of gas consendate leaking from the
temporary flange
The fire spread rapidly and was followed by a number
of smaller explosion
At around 10:20 pm a major explosion was followed by
the ruptering of a pipeline carrying gas to the Piper
Alpha platform from the nearby Texaco Tartan platform
The next few hours an intense high-pressure gas fire
raged, punctuated by a series of major explosions that
served to hasten the structural collapse of the platform

77. Most of the emergency systems on the platform, including the
fire water system, failed to come into operations
Of the 226 persons onboard the installation only 61 survived
The great majority of the of the survivors escaped by jumping
into the sea, some from as 175 feet (approx. 54 m)

78. Piper Alpha in flames

79. Crisis Management at Piper
Alpha
The explosion on the Piper Alpha that led to
the disaster was not devasting. We shall
never know, but it probably would have killed
only a small number of men
There was a number of critisim related to the
performance of the OIM on both Piper Alpha,
Claymore and Tartan platforms
These platforms were linked together by
pipelines and if the hydrocarbons from these
platforms had been stopped earlier, the
situation on Piper might have deterioated less
rapidly

80. On the evening of the crisis the platforms OIM was at
his cabin
In the control room at 9:55 pm a series of low gas
alarms was registered followed by a single high gas
alarm and a suddenly explosion
The stand by boat sent out a mayday call
By 10:05 several minutes after the explosion the OIM
arrived in the radio room wearing a survival suit and
instructed the radio operator to send out a mayday
The OIM left without giving further instructions or stating
his intentions

81. A few seconds later he ran into the radio room and told the
operator that area outside was on fire and that it should be
broadcasted that the platform was being abandoned
By this time people had started to muster in the
accomodation area an were waiting further instructions
Some of the emergency response teams made attempts to
tackle the fires or to effect rescues, but these were
uncoordinated and ineffective efforts in a desperate situation
By 10:20 pm 22 surviors had abandoned the platform – many
who had been working outside such as divers
Where people had mustered no one was in charge or giving
instructions and there was confusion

82. A second major explosion because of gas coming into the the
Piper from Tartan caused a massive high-pressure gas fire on
the platform
By 10:50 pm the structure of the platform was beginning to
collapse and gas fires were raging
The OIM and the majority of his crew died onboard as a result
of smoke inhalation
The report afterwards showed that the OIM took no initiative
in an attempt to save life but in his defense several
psychological factors could explain the OIM`s inadequate
leadership and poor decision making
He was under considerable stress and had not been properly
trained and smoke inhalation can effect cognitive functioning

83. The Claymore Platform

84. Crisis Management at
Claymore
However what was more suprising revealing serious
weaknesses in the oil industry`s provision for offshore
crisis management, was that the two other OIM`s on
duty from the linked platforms also failed to take
appropriate decisions
The Claymore platform situated 22 miles from Piper
needed to shut down the oil production to prevent it
from flowing towards the Piper platform
At 10:05 pm the Claymore OIM was told that there had
been a mayday on Piper due to fire and explosion
An attempt to contact Piper was unsuccessful and on
the secong mayday from Piper he sent a standby
vessel without shutting down the oil production

85. The operating superintendent at Claymore asked
the OIM if he could shut down the oil production.
The OIM refused this
The OIM at Claymore then called his manager in
Aberdeen. They knew that Pipers oil had been
shutdown. But as the pipeline pressure was
stable the OIM decided to continue the
production
10:30 they have heard that the fire on Piper was
spreading, and the operating superintendent
again asked the OIM to shut down oil production.
This was refused because he wanted to maintain
the production

86. During a later phonecall the OIM made
to the Production Manager the operating
superintendent shouted that there had
been an explosion on the Piper. The
Production Manager in Aberdeen asked
them to shut down immediately when he
found out that they were still operating
The Production Manager was suprised
that they were still operating and
instructed both Claymore and Tartan to
shut down production

87. Illustration of the Oil field
Piper Alpha
Claymore
Tartan

88. The Tartan Platform

89. Crisis Management on Tartan
Texaco`s Tartan was located 12 miles southwest of Piper and
also needed to shut down gas and oil production in the event
of an serious emergency on Piper
10:05 pm the OIM at Tartan heard mayday from Piper Alpha
The OIM could not see any flames so he did not shut down
the production but instructed his production supervisor to
monitor the gas pressure on the pipeline to Piper
Production was maintained on Tartan in the belief that Piper
was still producing (no telephone contact was possible)
10:25 the production supervisor was informed of a large
explosion on Piper. This explosion was in fact caused by the
hydrocarbons from Tartan

90. The emergency control was finally shut down and it took 5-10
minutes before the Tartan OIM asked for their gas line to be
depressurized and for the oil production to be shut down

91. Conclusion
The Piper Alpha disaster demonstrated the need for proper
training for the responsibility in this kind of position
This is just one of many crisis that have highlighted the need
for organizations to competent to deal with major crisis
Crisis Management is primarily dependent on the decision-making
of those in key command positions, at strategic,
tactical and operational levels
The immediate cause of the accident was due to
communication problems relating to shift handover and
Permit to Work procedures
This crisis also shows the importancy of good organizational
communication and information routines

92. What if...
There had been a proper shift-handover,
proper marking of the safety
valve that wasn`t functioning, or
proper Permit to Work for this shift at
the Piper Alpha?

93. Risk evaluation
Risk & unwanted incidents ranking
Systems in place
• Report incidents and near miss
• Analyse material
• Look for trends

94. Risk definition
Risk=Practicable*Consequence
Risk to
Personel
Environment
Material

95. Mapping of HSE & risks
Register incidents: Positive and
negative
Admin/M
gmt/QHSE
, 303
Marine,
669
Drilling,
463
Technical,
175
No name,
50
Catering,
191
Sub Sea,
48
Electrical,
137
Client, 137
Visitors,
12
3rd Party,
592

96. Cause assesment
• Direct causes vs underlying causes
• Cause persepctive
– Human
– Technical
– Organisational
• 5 Whys technique
– Look for underlying causes
– Eliminate root of the problem

97. HSE analyse
QRA: Quantity Risk Assesment
QRM: Qualitative Risk Matrix
Safe job analysis – Chemical
analysis
Risk assesment promt card

98. Risk reduction
ALARP: As Low As Reasonable
Practicable
BAT: Best Available Technology
Precation principles
Substitution principles

99. Barriers – swiss cheese
model
The Barriere Concept
BARRIERS;
Technical,
Qualifications,
Procedures
etc.
ACCIDENT/
ACCIDENT/
LOSS
LOSS
INITIATING
INITIATING
CAUSE
CAUSE

100. We are all responsible for managing
HSE
Hazard/
Risk
Barrier 1 – HSE Policy & Leadership
Barrier 2 – Planning
I was responsible for
planning the
operations safely

101. Hazard/
Risk
Barrier 1 – HSE Policy & Leadership
I was responsible
for supervising the
maintenance work
Barrier 2 – Planning
Barrier 3 – Supervision
I turned a blind eye to
some of the crew not
following all the
procedures as we had
limited time to do the job

102. Hazard/
Risk
Barrier 1 – HSE Policy & Leadership
Barrier 2 – Planning
Barrier 3 – Supervision
Barrier 4 – Procedures
I didn’t work safely
and took short-cut
to get the job done
Accident
I was responsible
completing the work

103. We all have a part to play
Maintenance
Maintain equipment and
ensure that operational
integrity is maintained
Hazards identified
and risk mngt plans
implemented
Visible leadership
promotes HSE
culture …..
Legal requirements
of projects identified
and complied with
Competencies required
for job are clearly
identified
Resources allocated
for effective
implementation
Legal
IT/ Data/
Graphics
HR
Mngt Team
SJA team
Drilling
Risk management integrated
to drilling programme
Contract
Ensure that Ocean Rig are
given the means to perform
the job safely and efficiently
HSE dept
Systems to control and
securely store HSE
critical information
Guidance and
advisory support
provided to
operations
Finance/Accounting
Resource budgets
effectively tracked
and managed

109. Pressure
Pressure (the symbol: P) is the force per unit area applied
in a direction perpendicular to the surface of an
object. Gauge pressure is the pressure relative to the local
atmospheric or ambient pressure.
Definition
Pressure is the effect of a force applied to a surface.
Pressure is the amount of force acting per unit area. The
symbol of pressure is P

110. Pressure in fluids at rest
Due to the fundamental nature of fluids, a fluid cannot
remain at rest under the presence of a shear stress.
However, fluids can exert pressure normal to any
contacting surface. If a point in the fluid is thought of as an
infinitesimally small cube, then it follows from the principles
of equilibrium that the pressure on every side of this unit of
fluid must be equal. If this were not the case, the fluid
would move in the direction of the resulting force.

111. Thus, the pressure on a fluid at rest is isotropic; i.e., it acts
with equal magnitude in all directions. This characteristic
allows fluids to transmit force through the length of pipes
or tubes; i.e., a force applied to a fluid in a pipe is
transmitted, via the fluid, to the other end of the pipe.
This concept was first formulated, in a slightly extended
form, by the French mathematician and philosopher Blaise
Pascal in 1647 and would later be known as Pascal's law.
This law has many important applications in hydraulics.

112. Hydrostatic pressure
See also vertical pressure variation.
Hydrostatic pressure is the pressure exerted by a fluid at
equilibrium due to the force of gravity.[1] A fluid in this
condition is known as a hydrostatic fluid. The hydrostatic
pressure can be determined from a control volume
analysis of an infinitesimally small cube of fluid. Since
pressure is defined as the force exerted on a test area
(p = F/A, with p: pressure, F: force normal to area A, A:
area), and the only force acting on any such small cube of
fluid is the weight of the fluid column above it, hydrostatic
pressure can be calculated according to the following
formula:

114. For water and other liquids, this integral can be simplified
significantly for many practical applications, based on the
following two assumptions: Since many liquids can be
considered incompressible, a reasonably good estimation
can be made from assuming a constant density throughout
the liquid. (The same assumption cannot be made within a
gaseous environment.) Also, since the height h of the fluid
column between z and z0 is often reasonably small
compared to the radius of the Earth, one can neglect the
variation of g. Under these circumstances, the integral
boils down to the simple formula:

115. where h is the height z-z0 of the liquid column between the
test volume and the zero reference point of the pressure.
Note that this reference point should lie at or below the
surface of the liquid. Otherwise, one has to split the
integral into two (or more) terms with the
constant ρliquid and ρ(z')above. For example, the absolute
pressure compared to vacuum is

116. where H is the total height of the liquid column above the
test area the surface, and patm is the atmospheric
pressure, i.e., the pressure calculated from the remaining
integral over the air column from the liquid surface to
infinity.
Hydrostatic pressure has been used in the preservation of
foods in a process called pascalization.[2]

117. Atmospheric pressure
Statistical mechanics shows that, for a gas of constant
temperature, T, its pressure, p will vary with height, h, as:
where: g = the acceleration due to gravity
T = Absolute temperature
k = Boltzmann constant
M = mass of a single molecule of gas
p = pressure
h = height
This is known as the barometric formula, and may be
derived from assuming the pressure is hydrostatic.
If there are multiple types of molecules in the gas,
the partial pressur

118. Pore pressure
The pressure of fluids within the pores of a reservoir, usually
hydrostatic pressure, or the pressure exerted by a column of
water from the formation's depth to sea level. When
impermeable rocks such as shales form as sediments are
compacted, their pore fluids cannot always escape and must
then support the total overlying rock column, leading to
anomalously high formation pressures.

119. If the rock has undergone a "normal" packing, we run the
risk abnormally high pore pressures (including
he abnormally high porosity).
The pore liquid can not disappear out of the rock at the time
of deposition pressed together and matured.
It requires dense materials, and therefore we find this most
often in limestone and clayrocks. If there is a lot of sand present,
the rock is much more permeable and pore liquid will
easier out under compression.

120. Darcy's law
Darcy's law is a phenomenologically derived constitutive
equation that describes the flow of a fluid through
a porous medium. The law was formulated by Henry
Darcy based on the results of experiments[1] on the flow
of water through beds of sand. It also forms the scientific basis of
fluid permeability used in the earth sciences, particularly
in hydrogeology.

121. Background
Although Darcy's law (an expression of conservation
of momentum) was determined experimentally by
Darcy, it has since been derived from the Navier-
Stokes equations via homogenization. It is analogous
to Fourier's law in the field of heat conduction, Ohm's
law in the field of electrical networks, or Fick's
law in diffusion theory.
One application of Darcy's law is to water flow
through an aquifer; Darcy's law along with the
equation of conservation of mass are equivalent to
the groundwater flow equation, one of the basic
relationships of hydrogeology. Darcy's law is also
used to describe oil, water, and gas flows through
petroleum reservoirs.

122. Description
Darcy's law is a simple proportional relationship between
the instantaneous discharge rate through a porous
medium, the viscosityof the fluid and the pressure drop
over a given distance.
Diagram showing definitions
and directions for Darcy's
law.

123. The total discharge, Q (units of volume per time, e.g.,
m³/s) is equal to the product of the permeability of the
medium, k (m2), the cross-sectional area to flow, A (units
of area, e.g., m2), and the pressure drop (Pa), all divided
by the viscosity, μ (Pa.s) and the length the pressure drop
is taking place over. The negative sign is needed because
fluids flows from high pressure to low pressure. So if the
change in pressure is negative (where Pa > Pb) then the
flow will be in the positive 'x' direction. Dividing both sides
of the equation by the area and using more general
notation leads to

124. where q is the flux (discharge per unit area, with units of
length per time, m/s) and is the pressure
gradient vector (Pa/m). This value of flux, often referred to
as the Darcy flux, is not the velocity which the water
traveling through the pores is experiencing. The pore
velocity (v) is related to the Darcy flux (q) by
the porosity (n). The flux is divided by porosity to account
for the fact that only a fraction of the total formation volume
is available for flow. The pore velocity would be the
velocity a conservative tracer would experience if carried
by the fluid through the formation.

125. Darcy's law is a simple mathematical statement which
neatly summarizes several familiar properties
that groundwater flowing in aquifers exhibits,
including:
If there is no pressure gradient over a distance, no
flow occurs (these are hydrostatic conditions), if there
is a pressure gradient, flow will occur from high
pressure towards low pressure (opposite the direction
of increasing gradient - hence the negative sign in
Darcy's law), the greater the pressure gradient
(through the same formation material), the greater the
discharge rate, and the discharge rate of fluid will
often be different — through different formation
materials (or even through the same material, in a
different direction) — even if the same pressure
gradient exists in both cases.

126. A graphical illustration of the use of the steady-state
groundwater flow equation (based on Darcy's
law and the conservation of mass) is in the
construction of flownets, to quantify the amount
of groundwater flowing under a dam.
Darcy's law is only valid for slow, viscous flow;
fortunately, most groundwater flow cases fall in this
category. Typically any flow with a Reynolds
number less than one is clearly laminar, and it would
be valid to apply Darcy's law. Experimental tests have
shown that flow regimes with Reynolds numbers up
to 10 may still be Darcian, as in the case of
groundwater flow. The Reynolds number (a
dimensionless parameter) for porous media flow is
typically expressed as

127. where ρ is the density of water (units of mass per
volume), v is the specific discharge (not the pore
velocity — with units of length per time), d30 is a
representative grain diameter for the porous media
(often taken as the 30% passing size from a grain
size analysis using sieves - with units of length),
and μ is the viscosity of the fluid.

128. Additional forms of Darcy's law
For very short time scales, a time derivative of flux
may be added to Darcy's law, which results in valid
solutions at very small times (in heat transfer, this is
called the modified form of Fourier's law),

129. where τ is a very small time constant which causes
this equation to reduce to the normal form of Darcy's
law at "normal" times (> nanoseconds). The main
reason for doing this is that the regular groundwater
flow equation (diffusion equation) leads
to singularities at constant head boundaries at very
small times. This form is more mathematically
rigorous, but leads to ahyperbolic groundwater flow
equation, which is more difficult to solve and is only
useful at very small times, typically out of the realm of
practical use.
Another extension to the traditional form of Darcy's
law is the Brinkman term, which is used to account
for transitional flow between boundaries (introduced
by Brinkman in 1947),

130. where β is an effective viscosity term. This correction
term accounts for flow through medium where the
grains of the media are porous themselves, but is
difficult to use, and is typically neglected.
Another derivation of Darcy's law is used extensively
in petroleum engineering to determine the flow
through permeable media - the most simple of which
is for a one dimensional, homogeneous rock
formation with a fluid of constant viscosity.

131. where Q is the flowrate of the formation (in units of
volume per unit time), k is the relative permeability of
the formation (typically in millidarcies), A is the cross-sectional
area of the formation, μ is the viscosity of
the fluid (typically in units of centipoise, and L is
the length of the porous media the fluid will flow
through. represents the pressure change per unit
length of the formation. This equation can also be
solved for permeability, allowing for relative
permeability to be calculated by forcing a fluid of
known viscosity through a core of a known length and
area, and measuring the pressure drop across the
length of the core.

132. Hole sections and well
trajectory
Drilling starts with 36 "holes down to 60-100m
Casing (30 ") at an early stage because of the danger
of infill of soft sediments. Casing is cast onto
the formation of cement on the outside.
Next section is drilled with a 26 "crown to depths of
between 400-800m. Casing (20 ") is the same
with cement on the outside.
On top of this place BOP

133. Production pipe cold tubing placed inside the well, a
little above the bottom.
At the bottom is a "production packer" placed.
100-500 from the top of the subsurface safety valve
(surface controlled sub surfacevalve, SCSSV) located
to ensure accidental outflow from the well.
At the top is placed a valve
system (production street) where we can control
production.

134. Next section is drilled with a 17 ½ “ crown and
casing at 13 5/8“
Often the last section with 12 ¼ “ crown and
9 5 /8" casing. We are now down in the reservoir
and the well can be prepared for production.
In some wells we drill even a section before the
reservoir is reached. This section is drilled with
8 ½ "crown and
casing 7". It is plain that this casing mounted on the 9
5 / 8"casing. This called for the liner.

136. Units

139. Well control
Primary well control is the name of the
process which maintains a hydrostatic
pressure in the well bore greater than
the pressure of the fluids in the
formation being drilled, but less than
the formation fracture pressure. If
hydrostatic pressure is less than
formation pressure then formation
fluids will enter the well bore.

140. If the hydrostatic pressure in the
wellbore exceeds the fracture
pressure of the formation pressure
then the fluid in the well will be lost. In
an extreeme case of lost circulation
the formation pressure may exceed
hydrostatic pressure allowing
formation fluid enter the well.

141. An over balance of hydrostatic
pressure over formation pressure is
maintained, this excess is generally
referred to as trip margin.

142. Secondary Well Control
If the pressure of the fluids in the
wellbore (i.e. mud) fail to prevent
formation fluids entering the wellbore,
the well will flow. This
process is stopped
using a ”blow out
preventer” to prevent
the escape of wellbore
fluids from the well.

143. This is the initial stage of secondary
well control. Containment of unwanted
formation fluids.

144. Tertiary well control
Tertiary well control describes the third
line of defence. Where the formation
cannot be controlled primary or
secondary well control (hydrostatic
and equipment). An underground
blowout for example. However in well
control it is not allways used as
qualitative term. ”Unusual well control
operations” listed below are
considered under this term:

145. a) A kick is taken with the kick off
bottom
b) The drill pipe plugs of during a kill
operation
c) There is no pipe in the hole
d) Hole in drill string
e) Lost circulation
f) Excessive casing pressure
g) Plugget and stuck off bottom
h) Gas percolation without gas
expansion

146. We could also include operations like
stripping or snubbing in the hole, or
drilling relief wells. The point to
remember is ”what is the well status at
shut in?” This determines the method
of well control.

150. Formation pressure
Formation pressure or pore pressure
is said to be normal when it is caused
solely by the hydrostatic head of the
subsurface wather contained in the
formations and there is pore to pore
pressure communication with the
atmosphere.

151. Dividing this pressure by the true vertical
depth gives an average pressure
gradient of the formation fluid, normally
between 0.433 psi/ft and 0.465 psi/ft.
The North Sea area pore pressure
averages 0.452 psi/ft. In the absence of
accurate data, 0.465 psi/ft which is the
average pore pressure gradient in the
Gulf of Mexico is often taken to be the
”normal” pressure gradient.
Note: The point at which atmospheric
contact is established may not
necessarily be at sea-level or rig site
level.

152. Normal formation pressure
Normal formation pressure is equal to
the hydrostatic pressure of water
extenting from the surface to the
subsurface formation. Thus the normal
formation pressure gradient in any
area will be equal to the hydrostatic
pressure gradient of the water
occupying the pore spaces of the
subspace formation in that area.

153. The magnitude of the hydrostatic
pressure gradient is affected by the
concentration of dissolved solids
(salts) and gases in the formation
water.
Increasing the dissolved solids (higher
salt concentration) increases the
formation pressure gradient whilst an
increase in the level of gases in
solution will decrease the pressure
gradient.

156. Abnormal pressure
Every pressure whis does not conform with
the definition given for normal pressure is
abnormal.
The principal causes of abnormal pressures
are:
Under compaction in shales
When first deposited, shale has a high
porosity. More than 50% of the total volume
of uncompacted clay-mud may consist of
water in which it is laid. During normal
compaction, a gradual reduction in porosity
accompanied by a loss of formation water is
squeezed out. As a result, water must be
removed from the shale before further

157. Not all of the expelled liquid is water,
hydrocarbons may also be flushed from
the shale.
If the balance between the rate of
companction and fluid expulsion is
disrupted such that fluid removal is
impeded then fluid pressures within the
shale will increase. The inability of shale
to expel water at a sufficient rate results
in a much higher porosity than expected
for the depth of shale burial in that area.

161. Salt beds
Continous salt depositions over large
areas can cause abnormal pressures.
Salt is totally impermeable to fluids and
behave plastically. It deforms and flows
by recrystallisation. Its properties of
pressure transmission are more like
fluids than solids, thereby exerting
pressures equal to the overburden load
in all directions. The fluids in the
underlying formations cannot escape as
there is no communication to the surface
and thus the formations become over
pressured.

162. Mineralisation
The alteration of sediments and their
constituent minerals can result in
variations of the total volume of the
minerals present. An increase in the
volume of these solids will result in an
increased fluid pressure. An example
of this occurs when anhydrite is laid
down. If it later takes on water
crystallisation, its structure changes to
become gysum, with a volume
increase of around 35%.

163. Tectonic causes
Is a compacting force that is applied
horizontally in subsurface formation. In
normal pressure environments water is
expelled from clays as they are being
compacted with increasing overburden
pressures. If however an additional horizontal
compacted with increasing overburden
pressures. If however an additional horizontal
compacting force squeezes the clays laterally
and if fluids are not able to escape at a rate
equal to the reduction in pore volume the
result will be an increase in pore pressure.

168. Formation fracture pressure
In order to plan to drill a well safely it
is necessary to have some knowledge
of the
fracture pressures of the formation to
be encountered. The maximum
volume of any uncontrolled influx to
the wellbore depends on the fracture
pressure of the exposed formations.

169. Formation fracture pressure
In order to plan to drill a well safely it
is necessary to have some knowledge
to the fracture pressures of the
formation to be encountered. The
maximum volume of any uncontrolled
influx to the wellbore depends on the
fracture pressure of the exposed
formations.

170. If well bore pressures were to equal or exceed this
fracture pressure, the formation would break down as
fracture was initiated, followed by loss of mud, loss of
hydrostatic pressure and loss of primary control.
Fracture pressures are related to the weight of the
formation matrix (Rock) and the fluids (water/ oil)
occupying the pore space with in the matrix, above the
zone of interest. These who factors combine to produce
what is known as the overburden pressure. Assuming
the average density of a thick sedimentary sequence to
be the equivalent of 19.2 ppg then the overburden
gradient is given by
0.052 * 19.2 = 1.0 psi/ft
Since the degree of compaction of sediments is known
to vary with depth the gradient is not constant.

172. Onshore, since the sediments tend to
be more compacted, the overburden
gradient can be taken as being close
to 1.0 psi/pf due to the effect of the
depth of seawater and large
thicknesses of unconsolidated
sediment. This makes surface casing
seats in offshore wells much more
vulnerable to break down and is the
reason why shallow gas kicks should
never be shut in.

174. Leak-off tests
The leak-off test establishes a
practical value for the input into
fracture pressure predictions and
indicates the limit of the amount of
pressure that can be applied to the
wellbore over the next section of hole
drilled. It provides the basic data
needed for further fracture calculations
and it also tests the effectiveness of
the cement job.

175. The test is performed by applying an
incremental pressure from the surface to the
closed wellbore/ casing system until it can be
seen that fluid is being injected into the
formation. Leak-off tests should normally be
taken to this leak-off pressure unless it
exceeds the pressure to which the casing
was tested. In some instances as when
drilling development wells this might not be
necessary and a formation competecy test,
where the pressure is only increased to a
predermined limit, might be all that is
required.

176. Leak-off test procedure
Before starting, gauges should be
checked for accuracy. The upper
pressure limit should be determined.
1. The casing should be tested prior to
drilling out the shoe
2. Drill out the shoe and cement,
exposing 5-10 ft of new formation
3. Circulate and condition the mud,
check mud density in and out

177. 4. Pull the bit inside the casing. Line up cement
pump and flush all lines to be used for the test.
5. Close BOPs
6. With the well closed in, the cement pump is
used to pump a small volume at a time into the
well typically a ¼ or ½ bbl per min. Monitor the
pressure build up and accurately record the
volume of mud pumped. Plot pressure versus
volume of mud pumped
7. Stop the pump and when any deviation from
linearity is noticed between pump pressure and
volume pumped
8. Bleed off the pressure and establish the
amounts of mud, if any, lost to the formation

179. Working example of leak-off test
procedure (floating rigs)
”Operational drilling procedures for
floating rigs” is designed to determine
the equivalent mud weight at which
the formation will accept fluid. This
test is not designed to bread down or
fracture the formation. This test is
normally performed at each casing
shoe

180. Prior to the formation leak-off, have
”handy” a piece of graph paper, pencil
and straight edge (ruler). Utilising the
high pressure cement pumping unit,
perform leak-off as follows:

181. 1. Upon drilling float equipment, clean
out rat hole and drill 15 ft of new
hole. Circulate and condition hole
clean. Be assured mud weight in and
mud weight out balance for most
accurate results.
2. Pull bit up to just above casing shoe.
Install head on DP

182. 3. Rig up cement unit and fill lines with
mud. Test lines to 2500 psi. Break
circulation with cement unit, be
assured bit nozzles are clear. Stop
pumping when circulation established.
4. Close pipe rams. Position and set
motion compensator, overpull drillpipe
(+/- 10,000 lbs), close choke/ kill
valves.

183. 5. At slow rate (1/4 or ½ BPM), pump
mud down DP
6a Pump ¼ bbl – record pressure on
graph paper
b Pump ¼ bbl – record pressure on
graph paper
c Pump ¼ bbl – record pressure on
graph paper

184. d Pump ¼ bbl – record pressure on
graph paper
e Pump ¼ bbl – record pressure on
graph paper
f Continue this slow pumping. Record
pressure at ¼ bbl increments until two
points past leak-off.
g Upon two points above leak-off, stop
pumping. Allow pressure to stabilize.
Record this stabilized standing pressure
(normally will stabilixe after 15 mins or
so)

185. h Bleed back pressure into cement
unit tanks. Record volume of bleed
back
i Set and position motion
compensator, open rams.
j Rig down and cement unit lines.
Proceed with drilling operations.
k Leak-off can be repeated after step
6 if data confirmation is required,
otherwise leak-off test is complete.

186. Note: For 20” and 13 3/8” csg leak-off
tests, plot pressure every ½ bbl. Results
will be the same.
It should be noted that in order to obtain
the proper leak-off and pumping rate
plot, it will be necessary to establish a
continous pump rate at a slow rate in
order to allow time to read the pressure
and plot the point on the graph. (Barrels
pumped vs. pressure-psi), normally ½
BPM is sufficient time.

187. A pressure gauge of 0-2000 psi with
20 or 25 increments is recommended.
Note: In the event Standing Pressure
is lower than leak-off point. Use
standing pressure to calculate
equivalent mud weight. Always note
volume of mud bled back into tanks.

196. Rig components

207. An introduction to petroleum geology
Sedimentology
The great majority of hydrocarbon reserves worldwide
occur in sedimentary rocks.
It is therefore vitally important to understand the nature and
distribution of sediments as potential hydrocarbon source
rocks and reservoirs. Two main groups of sedimentary rocks
are of major importance as reservoirs, namely siltstones and
sandstones (‘clastic’ sediments) and limestones and
dolomites (‘carbonates’). Although carbonate rocks form
the main reservoirs in certain parts of the world (e.g. in the
Middle East, where a high proportion of the world’s giant
oilfields are reservoired in carbonates), clastic rocks form
the most significant reservoirs throughout most of the
world.

208. CLASSIFICATION OF SEDIMENTARY
ROCKS

209. Texture in Granular Sediments
The main textural components of granular rocks include:
grain size
grain sorting
packing
sediment fabric
grain morphology
grain surface texture

210. Grain size

211. Sorting

212. Grain shape

213. Packing

214. Sand and sandstone
Sands are defined as sediments with a mean grain size
between 0.0625 and 2 mm which, on compaction and
cementation will become sandstones. Sandstones form the
bulk of clastic hydrocarbon reservoirs, as they commonly
have high porosities and permeabilities.
Sandstones are classified on the basis of their composition
(mineralogical content) and texture (matrix content). The most
common grains in sandstones are quartz, feldspar and
fragments of older rocks. These rock fragments may include
fragments of igneous, metamorphic and older sedimentary
rocks.

215. Classification of sands and sandstones

216. Porosity
Total porosity (φ) is defined as the volume of void (pore)
space within a rock, expressed as a fraction or percentage of
the total rock volume. It is a measure of a rock’s fluid storage
capacity.
The effective porosity of a rock is defined as the ratio of the
interconnected pore volume to the bulk volume
Microporosity (φm) consists of pores less than 0.5 microns in
size, whereas pores greater than 0.5 microns form
macroporosity (φM)

217. Permeability
The permeability of a rock is a measure of its capacity to
transmit a fluid under a potential gradient (pressure drop).
The unit of permeability is the Darcy, which is defined by
Darcy’s Law. The millidarcy (1/1000th Darcy) is generally
used in core analysis.

218. Controls on Porosity and
Permeability
The porosity and permeability of the sedimentary rock
depend on both the original texture of a sediment and its
diagenetic history.

219. Grain size
In theory, porosity is independent of grain size, as it is
merely a measure of the proportion of pore space in the rock,
not the size of the pores. In practice, however, porosity
tends to increase with decreasing grain size for two
reasons. Finer grains, especially clays, tend to have less
regular shapes than coarser grains, and so are often less
efficiently packed. Also, fine sediments are commonly better
sorted than coarser sediments. Both of these factors result
in higher porosities.
For example, clays can have primary porosities of 50%-85%
and fine sand can have 48% porosity whereas the primary
porosity of coarse sand rarely exceeds 40%.
Permeability decreases with decreasing grain size because
the size of pores and pore throats will also be smaller,
leading to increased grain surface drag effects.

220. Porosity: Function of grain size
and sorting

221. Grain Shape
◦ The more unequidimensional the grain shape, the greater the
porosity
◦ As permeability is a vector, rather than scalar property, grain
shape will affect the anisotropy of the permeability. The more
unequidimensional the grains, the more anisotropic the
permeability tensor.
Packing
◦ The closer the packing, the lower the porosity and
permeability
Fabric
◦ Rock fabric will have the greatest influence on porosity and
permeability when the grains are non spherical (i.e. are either
disc-like or rod-like). In these cases, the porosity and
permeability of the sediment will decrease with increased
alignment of the grains.
Grain Morphology and Surface Texture
◦ The smoother the grain surface, the higher the permeability

222. Diagenesis (e.g. Compaction,
Cementation)
Diagenesis is the totality of physical and chemical
processes which occur after deposition of a
sediment and during burial and which turn the
sediment into a sedimentary rock. The majority of
these processes, including compaction,
cementation and the precipitation of authigenic
clays, tend to reduce porosity and permeability,
but others, such as grain or cement dissolution,
may increase porosity and permeability. In general,
porosity reduces exponentially with burial depth,
but burial duration also an important criterion.
Sediments that have spent a long time at great
depths will tend to have lower porosities and
permeabilities than those which have been rapidly
buried.

223. Changes of porosity with burial
depth

224. Drilling bits

255. Wireline operations at Varg A

256. Measurement While Drilling