This document provides information on various topics related to well planning and design, including: - Well data requirements such as detailed lithology, formation fluids, reservoir data, and pressure data. - Global basin screening, basin analysis, play analysis, prospect analysis, rock types, and reactive formations. - Exploration strategy, including global basin analysis, basin analysis, play analysis, prospect analysis, and prospect volume estimation. - Pore pressure and fracture pressure determination, including leakage tests to estimate the fracture gradient at casing seats.

1. SubsurfaceSignificanceIn
WellEngineering
Organizes Course on:
Advanced Well
Planning & Design &
Engineering Course
I
n Association with
Dr
. Nitesh Kumar,
Founder / Owner MDNK
Oil & Gas Consultants

2. Well Data for design
• Detailed lithology – reactive formations, fractured
or connected, thick or thin reservoirs
• Formation fluids- oil, gas, water in various sections,
corrosive fluids like H2S, CO2 or chlorides – casing
and tubing selection
• Reservoir data – reservoir units and tops, fluid
contacts, transition zones, salt zones etc
• Pressure data for preliminary casing seat selection
from PPFG plot – ppg in x axis and depth in feet's.
FIT to further modify casing seat in field.

3. • Global basin screening
• Basin analysis
• Play analysis
• Prospect analysis
• Reservoir rock types
• Detailed lithology – reactive formations, fractured
or connected, thick or thin reservoirs
Exploration Strategy
06-04-2023

4. Global Basin Analysis
In major oil companies operating
worldwide, geoscientists screen
the entire world for attractive
opportunities based on their
regional knowledge and
subsurface competence. Projects
are ranked and prioritized
globally to ensure big oil
companies pursue the most
attractive opportunities.
06-04-2023
180°W 140°W 100°W 60°W 20°W 20°E 60°E 100°E 140°E 180°E
40°S
0°N 0°N
40°N
80°N 80°N
180°W
180°W
180°E
180°E
arcmap20030314_kruud_RWPS_World_Screening_Ranking_Overview_Screened_A3.mxd
Projection: World_Winkel_Tripel_NGS
mapdata@statoil.com
Screening and Ranking Overview (RWPS)
Screened Basins
Screened
Basins Screened (642)

5. Basin Analysis
It is a geologic method by
which the history of
a basin (sedimentary
etc) is revealed, by
analyzing the sediment fill
itself. Aspects of the
sediment, namely its
composition, primary
structures, and internal
architecture, can be
synthesized into a history
of the basin fill.
06-04-2023

6. Play Analysis
• A petroleum play, is a group of oil fields or prospects in the
same region that are controlled by the same set of geological
circumstances. The term is widely used in the realm of
exploitation of hydrocarbon-based resources.
• The play cycle normally exhibits the following steps:
• Initial observations of a possible oil reserve
• testing and adjustments to initial estimates of extraction
• high success in locating and extracting oil from a reserve
• lower success as the reserve is depleted
• Continued decrease in further exploration of the region
A particular stratigraphic or structural geologic setting is also
often known as a play. For example, in the Gulf of Mexico,
explorers refer to the "Wilcox play" or the "Norphlet play" to
collectively designate the production and possible production
from those particular geological formations, of Paleocene and
Jurassic age respectively.
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Pl

7. Prospect Analysis
• Prospect Decisions Require
Methodical Analysis
• Technical Risk Evaluation &
Economic Evaluation
• Rank the prospects by risk
• Drill the best one, then re-
evaluate the others
06-04-2023
Risk Factors
• Hydrocarbon charge
• Source Rock Quality (TOC, Kerogen
type) / Thermal modelling
• Maturity of Source Rock
• Migration Pathways
• Reservoir Porosity / Permeability
• Prospect volume estimation
• Top Seal, Fault Seal (Trapping
efficiency)
• Timing

8. Thermal History Matching

9. Rock Types
• Lithology is a geological term used to describe the types
of formation rocks.
• Out of three types of rocks, only sedimentary rocks carry
hydrocarbons, metamorphic, and igneous rarely have
any HC reserves.
• Sedimentary rocks are rocks formed after compaction of
settled solid particles in water.
• Due to continuous rock erosion downstream, particles
settle to the bottom of the rivers, lakes, and oceans in
layer after layer.
• These layers are pressed down through time, until heat
and pressure slowly turn the lower layers into rock.

10. Sedimentary Rocks
• Gravels, sandstones, siltstones, shales,
and mudstones, carbonates are some of the
subclasses of sedimentary rocks. These subclasses
are generally porous and can contain water and
hydrocarbons.
• Two examples of carbonate rocks are limestone
and dolomite, composed of calcite (CaCO3) and
the mineral dolomite (CaMg(CO3)2), respectively.
• Carbonate rocks are very tight—that is, they
display low porosity and permeability but are
highly fractured and may contain water and
hydrocarbons.

11. Reactive Formations
• During the drilling of oil wells, it is common to
encounter the presence of layers consisting of clay
minerals with high degree of hydration and
arranged in laminar packages.
• When in contact with water, the packets of the clay
are separated as the water enters in the basal
spacing.
• Argillaceous formations such as shales containing
smectite are sensitive to the presence of water and
the greater the amount of smectite, higher
reactivity in the presence of water. This
phenomenon is known as expansion or swelling.
• Shale swelling is a primary cause of wellbore
instability. Water based muds can cause shale
swelling, lead to GUMBO attack.

12. Reservoir Rocks
• Reservoir rocks are rocks that have the ability to store fluids inside their
pores, so that the fluids (water, oil, and gas) can be accumulated.
• These are sedimentary rocks like sandstones and dolomites.
• Reservoir has a cap rock, ie a formation which protects the reservoir fluids
from migrating.
• Reservoir rock must have good porosity and permeability to accumulate and
drain oil in economical quantities.
• Important reservoir petrophysical properties are:
• Porosity
• Permeability
• Net thickness

13. Porosity
• Porosity is the void space in a rock that can store the fluids.
• It is measured as either a volume percentage or a fraction (expressed as a
decimal).
• In the subsurface this volume may be filled with petroleum (oil and gas),
water, a range of non hydrocarbon gasses (CO2, H2S, N2), or some
combination of these.
• Porosity divided into two types, absolute porosity and effective porosity.
• Absolute porosity is the ratio of the total pore volume in the rock to bulk
volume, where as effective porosity is the ratio of interconnected pore
volume to bulk volume.

14. Permeability
• Permeability is an intrinsic property of a material that determines how easily a
fluid can pass through it.
• In the petroleum industry, the Darcy (D) is the standard unit of permeability, but
mili darcies (1 mD = 10-3 D) are more commonly used.
• A Darcy is defined as a flow rate of 10-2 ms-1 for a fluid of 1 cp (centipoise) under a
pressure of 10-4atm m-2.
• Permeability in reservoir rocks may range from 0.1 mD to more than 10 D.
• Two terms used for Permeability, absolute and relative perm.
• Absolute Permeability is the ability of a reservoir rock to allow fluids to flow
through its pores. It indicates the flow capacity of formation. It is simply referred
to as permeability.
• In multiphase flow in porous media, the relative permeability of a phase is a
dimensionless measure of the effective permeability of that phase. It is the ratio
of the effective permeability of that phase to the absolute permeability.

15. Prospect
Volume
Estimation

16. Results:
Cumulative
distributions
of risked and
un-risked
resources

17. Pore Pressure &
Fracture
Pressure
 Pore pressure
 The pressure of the formation fluids.
 Fracture pressure
 The pressure to fracture the formation.
 Design criteria
 Pore Pressure < Mud Pressure < Fracture
Pressure
 Consequences of poor design:
 Formation fluids flows into the borehole if mud
pressure is less than the pore pressure.
 Lost circulation occurs if mud pressure
exceeds the fracture pressure.

18. Normal Pore Pressure Abnormal Pore Pressure 0.433 - 0.465 psi/ft gp > normal

19. 19

20. Formation Pressure
• The formation fluid pressure, or pore pressure, is the pressure exerted by the fluids within
the formations being drilled.
• The sedimentary rocks, which are of primary importance in the search for, and
development of oilfields, contain fluid due to their mode of formation.

21. 21
CIRCULATING PRESSURE: The pressure required to over come friction between the fluid and
whatever it comes into contact with as it moves through the circulation cycle (Pump standpipe
pressure).
Varies with:
Fluid density (), viscosity (PV, YP, Gels)
Size and length of tubulars
Size of bit nozzles
X-sectional area of annulus
Flow rate (Q in gpm)

22. 22
SURFACE PRESSURE: Pressure that is applied at surface. Any pressure applied at the surface will be
equally reflected, in all directions, throughout the wellbore.
At bottom: P = PH + Ps psi
At other depths P= Ps + PH (at that depth)
It is important to ensure that any applied surface pressure does not cause you to
exceed the pressure that a given down hole formation can with stand [frac pressure]

23. 23
FRACTURE PRESSURE: The pressure at which a formation will break down. Permanent damage
is done to the rock matrix. It is very important to know the fracture pressure of the various
formations.
1. As the well is deepened it can be expected that density will have to increase to
control formation pressures. We must be sure that the increased density will not fracture an
upper zone.
2. If a “kick” occurs we must be aware of the maximum pressure that can be safely
held at surface without fracturing the csg seat.
3. The formation and/or the cement at the casing shoe will generally be a week-point
[Lowest fracture gradient].

24. 24
Fracture gradient or Fracture pressure is a
formations strength and ability to withstand
pressure.
It is important to know the value since if the
Fracture Gradient pressure is exceeded, the
formation or well bore will fracture and loss of
drilling fluid will occur.
A Formation Leak-off (LOT) test is used to
measure the fracture gradient.

25. 25
MASP
It is normal practice to test the casing seat of the latest string of casing to estimate the fracture pressure
at that point.
Knowing the Fg at the shoe will allow us to determine the maximum back pressure that can be help on
the well. {Maximum Allowable Surface Pressure (MASP)}
MASP = [Fg - g]* Ds
Each time the density of the drilling fluid changes a new MASP must be calculated.

26. 26
LEAK-OFF TEST (LOT)
The test is conducted by “shutting the well in” and applying surface pressure until the “Leak-Off” point is
reached.
TEST PROCEDURE
Drill out shoe and make ± 10’ of new hole
Circulate the hole clean of cuttings
Shut the well in using the pipe rams
Start to pump at a low but constant rate
Use an accurate pressure recorder to record surface pressure and volume pumped.
LOP = applied surface pressure + HP

27. 27
LEAK-OFF TEST
The point at which the plotted values break from a straight line is the LEAK_OFF point. All
pumping must stop at the is point to prevent fracture of the formation.
Record the break point (where the relationship deviates fron a straight line) to calculate the Fg
LOg = [Total pressure at the shoe (HP + Applied surface pressure)/D] psi/ft
EMW = [Total pressure at the shoe (HP + Applied surface pressure)/(D*0.052)] ppg
Care must be taken when conducting this test as there is a very real danger of
fracturing the casing seat.

28. 28
Typical Rig Up for LOT

29. 29
LEAK-OFF TEST
LEAK-OFF TEST
0
50
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550
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650
700
750
800
850
900
950
1000
0 1 1.5 2 2.5 3.5 4 5 6 6.5 7 8 9 10
BBL
SURFACE
PRESSURE
LEAK-OFF
FRACTURE
Applied surface pressure

30. 30
LEAK-OFF TEST
Using a test DF with  = 8.34 ppg, a shoe depth of 1800’ and the values from the Leak-Off plot:
PH = 8.34*1800*.052 = 780 psi
Applied surface pressure = 725 psi
LOP = 780 + 725 = 1505 psi
LOg = 1505/1800 = 0.83 psi/ft
MWE = 0.83/0.052 = 15.9 ppg
MASP = applied surface pressure = 725 psi
If density is increase to 9 ppg
MASP = 1505 – (9*1800*0.052) = 1505-842 = 663 psi

31. 31
FORMATION
INTERGITY TEST
(FIT)
This test is much the same as the LOT with the exception that we do not
attempt to determine the Leak-off point.
Off-set well data is used to determine the maximum pressure that will be encountered in
the next section of the wellbore.
A safety factor is added to this value to determine the MASP required to drill the section.
The formation is then tested to that value
A close watch is kept on the pressure plot to ensure that the formation does not fracture
prior to reaching the calculated value needed

32. 32
FORMATION
INTERGITY TEST
(FIT)
FORMATION INTEGRITY TEST
0
50
100
150
200
250
300
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400
450
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550
600
650
700
750
800
850
900
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1000
0 1 1.5 2 2.5 3.5 4 5 6 6.5 7 8 9 10
BBL
SURFACE
PRESSURE
LEAK-OFF
FRACTURE
REQUIRED PRESSURE

33. 33
CEMENT FAILURE
CEMENT CHANNELING
0
100
200
300
400
500
600
700
800
900
1000
0
3
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9
5
1
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1
8
5
2
1
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2
7
5
VOLUME
SURFACE
PRESSURE
EXPECTED LEAK-OFF
STOP PUMPS
LEAK-OFF

34. 34
FORMATION
INTERGITY TEST
(FIT)
From Off-set data it was determined that a LOP of 1380 psi [PH of 780 psi + 600 psi applied pressure]
would provide a sufficient safety factor to drill the next segment of the well.
The FIT would be conducted as shown and when the applied pressure reaches 600 psi the test would
stop.
The test is closely monitored to ensure that the Leak-Off point does not occur before the desired
600 psi is reached.

35. 35
Casing was set at 10,000 ft in the well.
After drilling out the shoe track and 15 ft of new formation, the
well was circulated to the new 11.2 ppg mud.
The operator performed a LOT which showed leak-off at 2700 psi
applied surface pressure.
1. What is the fracture gradient at the casing
shoe?
2. If the maximum expected pressure in the next interval has a
MWE = 14.5 ppg, what FIT value would be acceptable if a safety
factor of 1.25 ppg is to be used?
Exercise 1

36. 36
At the well planning stage, the fracture gradient can be estimated
from offset well data. If no offset data is available the fracture
gradient can be predicted using any of the published models.
Theoretical determination
Fracture gradient can be determined using :
Hubbert & Willis: The fracture gradient is a function of overburden
stress, formation pressure and a relationship between horizontal and
vertical stresses
Mathews & Kelly: Consider the matrix stress and varies only with the
degree of compaction
Eaton: Extended concept from Mathews and
Kelly by introducing Poisson ratio
Christman: Accounted for the effect of water depth

37. 37
1. Hp = 10000*0.052*11.2 = 5825 psi
 Ps = 2700 psi
LOP = 5825 + 2700 = 8525 psi
LOg = 8525/10000 = 0.853 psi/ft
MWE = 0.853/0.052 = 16.3 ppg
2. FIT
 HpFIT = 10000*0.052*15.75 = 8190 psi
 Ps = 8190 – 5825 = 2365 psi
 Thus the applied surface pressure for the FIT would be 2365 psi
Exercise 1 Solutions

38. 38
Eaton - commonly used method
F = S -P ( v ) + P
D 1 - v D
where : P = well bore pressure (psi)
D = depth (ft)
S = overburden stress (psi)
v = Poisson’s ratio
F = fracture gradient (psi/ft)

39. 39
Exercise 2 : Estimation of Fracture Gradient
Using the data below, calculate the fracture gradient at the various
depths for the following land well. Assume v = 0.4 and overburden
gradient = 1.0 psi/ft.
5984
9000
7800
10000
6810
9500
10171
11000
4504
8500
4067
8300
2450
5000
1320
3000
Pore Pressure (psi)
TVD (ft)

40. Assignment for Thought
• Do you have a shallow seismic plot available for your well? Can you identify the bright
spots and what they mean for your well and casing seat selection? If this information is
unavailable, what information do you have?
• Can you figure out the geological stratigraphy for well? What do you learn from it? Can
you identify the various strata’s on the stratigraphic column.
• Based on the problem set given, come up with a proper pore pressure fracture
gradient plot for your well.
• Add and subtract 0.5 ppg from PP and FG respectively. Perform bottoms up seat
selection.
• Identify target sands based on instructors notes and put them on the PPFG plot
• Can you put together a mud sheet on excel for your well?
• Can you do burst, collapse and tensile design for 13-5/8” and 11-7/8” casing string for
this well?
• What other considerations did you take in determining your casing seat program?
• Put together a document of all the plots generated and obtained, which should go in
the final report.