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ABNORMAL FORMATION PRESSURE ANALYSIS
Version 2.1 February 2001
Dave Hawker
Corporate Mission To be a worldwide leader in providing drilling
and geological monitoring solutions to the oil and gas
industry, by utilizing innovative technologies and delivering
exceptional customer service.
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DATALOG: ABNORMAL FORMATION PRESSURE ANALYSIS, Version 2.1,
issued February 2001
DATALOG: ABNORMAL FORMATION PRESSURE ANALYSIS, Version 2.1,
issued February 2001
1
CONTENTS
1.
INTRODUCTION................................................................................................................................................
4
2. PRESSURES &
GRADIENTS............................................................................................................................
5 2.1 HYDROSTATIC
PRESSURE..................................................................................................................................
5 2.2 FORMATION PRESSURE
.....................................................................................................................................
8
2.2.1 Direct Pressure Measurements
.................................................................................................................
9 2.2.1.1 Repeat Formation Test
.......................................................................................................................
9 2.2.1.2 Drill Stem Test
...................................................................................................................................
9
2.2.2 Indirect Pressure
Measurements.............................................................................................................
10 2.2.2.1 Kick Shut-In Pressures
.....................................................................................................................
10 2.2.2.2 Connection
Gases.............................................................................................................................
11
2.3 FRACTURE PRESSURE
.....................................................................................................................................
12 2.3.1 Leak Off
Tests..........................................................................................................................................
13
2.4 OVERBURDEN
STRESS.....................................................................................................................................
16 2.4.1 Determination of Bulk
Density................................................................................................................
17
2.4.1.1 Bulk Density from
Cuttings..............................................................................................................
18 2.4.1.2 Bulk Density from Sonic Logs
.........................................................................................................
19
2.4.2 Calculation of Overburden Gradient
......................................................................................................
20 2.5 BALANCING WELLBORE
PRESSURES...............................................................................................................
24
2.5.1 Mud Hydrostatic
.....................................................................................................................................
24 2.5.2 Equivalent Circulating
Density...............................................................................................................
25 2.5.3 Surge
Pressures.......................................................................................................................................
26 2.5.4 Swab Pressures
.......................................................................................................................................
26 2.5.5 Kick Tolerance
........................................................................................................................................
28
2.5.5.1 Kick Tolerance, worked
example.....................................................................................................
30 2.6 SUMMARY OF FORMULAE
................................................................................................................................33
3 OCCURRENCES OF ABNORMAL FORMATION
PRESSURE.................................................................
35 3.1 UNDERPRESSURED
FORMATIONS.....................................................................................................................
35
3.1.1 Reductions in Confining Pressure or Fluid Volume
...............................................................................
35 3.1.2 Apparent
Underpressure.........................................................................................................................
35
3.2 OVERPRESSURE
REQUIREMENTS.....................................................................................................................
37 3.2.1 Overpressure
Model................................................................................................................................
37
3.2.1.1 Permeability
.....................................................................................................................................
37 3.2.1.3 Fluid Type
........................................................................................................................................
38
3.3 CAUSES OF
OVERPRESSURE............................................................................................................................
39 3.3.1 Overburden Effect
...................................................................................................................................
39 3.3.2 Tectonic Loading
....................................................................................................................................
41
3.3.2.1 Faulting
............................................................................................................................................
41 3.3.2.2 Deltaic Environments
.......................................................................................................................
42 3.3.2.3 Diapirism/Domes
.............................................................................................................................
43
3.3.3 Increases in Fluid Volume
......................................................................................................................
44 3.3.3.1 Clay
Diagenesis................................................................................................................................
44 3.3.3.2 Gypsum Dehydration
.......................................................................................................................
45 3.3.3.3 Hydrocarbon or Methane
Generation...............................................................................................
45 3.3.3.4 Talik and Pingo
Development..........................................................................................................
45 3.3.3.5 Aquathermal Expansion
...................................................................................................................
46
3.3.4 Osmosis
...................................................................................................................................................
46
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3.3.5 Hydrostatic causes
..................................................................................................................................
47 3.3.5.1 Hydraulic Head
................................................................................................................................
47 3.3.5.2 Hydrocarbon
Reservoirs....................................................................................................................47
4 OVERPRESSURE
DETECTION......................................................................................................................
48 4.1 BEFORE
DRILLING...........................................................................................................................................
48 4.2 REAL-TIME INDICATORS
.................................................................................................................................
49
4.2.1 Rate of Penetration
.................................................................................................................................
49 4.2.2 Drilling
Exponent....................................................................................................................................
50 4.2.3 Corrected Drilling
Exponent...................................................................................................................
51 4.2.4 Trend/Shift Changes and
Limitations......................................................................................................
53
4.2.4.1
Lithology..........................................................................................................................................
53 4.2.4.2 Bit Type and Wear
...........................................................................................................................
55 4.2.4.3 Fluid
Hydraulics...............................................................................................................................
56 4.2.4.4 Significant Parameter
Changes.........................................................................................................
56 4.2.4.5 Directional Drilling
..........................................................................................................................
56
4.2.5 Torque, Drag and Overpull
.....................................................................................................................
57 4.2.6 Tripping Indicators
.................................................................................................................................
57
4.3 LAGGED
INDICATORS......................................................................................................................................
58 4.3.1 Background Gas
Trends..........................................................................................................................
58
4.3.1.1 Sealed
Overpressure.........................................................................................................................
59 4.3.1.2 Transitional Overpressure
................................................................................................................
59
4.3.2 Connection
Gas.......................................................................................................................................
61 4.3.3
Temperature............................................................................................................................................
66
4.3.3.1 Geothermal Gradient
........................................................................................................................
66 4.3.3.2 Flowline Temperature
......................................................................................................................
67 4.3.3.3 Delta T
.............................................................................................................................................
68 4.3.3.4 Trends
..............................................................................................................................................
69
4.3.4 Analysis of Drilled Cuttings
....................................................................................................................
70 4.3.4.1 Shale Density
...................................................................................................................................
70 4.3.4.2 Pressure Cavings
..............................................................................................................................
71 4.3.4.3 Shale
Factor......................................................................................................................................
72
4.4 INFLUX INDICATORS
.......................................................................................................................................
73 4.5 WIRELINE / LWD INDICATORS
.......................................................................................................................
74
4.5.1 Sonic Transit Time
..................................................................................................................................
74 4.5.2 Resistivity
................................................................................................................................................
75 4.5.3 Density
....................................................................................................................................................
76 4.5.4 Neutron Porosity
.....................................................................................................................................
76 4.5.5 Gamma
Ray.............................................................................................................................................
77 4.5.6 Wireline Examples
..................................................................................................................................
78
5. QUANTITATIVE PRESSURE
ANALYSIS....................................................................................................
81 5.1 CALCULATION
TECHNIQUES............................................................................................................................
81
5.1.1 Eatons Method
........................................................................................................................................
82 5.1.2 Equivalent Depth Method
......................................................................................................................
85 5.1.3 Ratio
Method...........................................................................................................................................
87
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6. CALCULATION OF FRACTURE
GRADIENT............................................................................................
88 6.1 GENERAL
THEORY..........................................................................................................................................
89 6.2 CALCULATION
METHODS................................................................................................................................
90
6.2.1 Eatons Method
........................................................................................................................................
90 6.2.2 Poissons From Shaliness
Index...............................................................................................................
90 6.2.3 Daines Method
........................................................................................................................................
92
7. USE OF THE QLOG SOFTWARE
.................................................................................................................
94 7.1 GENERAL
PROCEDURE....................................................................................................................................
94 7.2 OVERBURDEN PROGRAM
................................................................................................................................
95 7.3 OVERPRESSURE PROGRAM
.............................................................................................................................
97
7.3.1 Multiple
NCTs.......................................................................................................................................
100
8.
EXERCISES.....................................................................................................................................................
101
9. BIBLIOGRAPHY
............................................................................................................................................
112
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1. INTRODUCTION In order to properly plan a well program and to
drill a well, both safely and economically, knowledge and
understanding of formation pressures and fracture gradients is
essential. This allows mud densities, and positioning of casing
shoes, to be optimised to provide sufficient balance against
formation pressures while not being to high so that formations are
at risk of being damaged or fracture. Formation pressure analysis
is, therefore, an integral part of any drilling operation. It is
one of the most important services provided by a mud logging
service, but is almost one of the, technically, most demanding.
Pressure Engineers assume a great deal of responsibility since
their analyses and predictions are of genuine importance to the
success of a drilling operation. Many sources of data have to be
evaluated alongside each other before a reliable analysis can be
made. Often, different sources of information may give conflicting
results, in terms of predicting pressure changes, so that the
engineer has to evaluate which sources of data are the most
reliable. Often, different environments or different drilling
regimes will result in different data sources being the most
reliable, so from a pressure analysis perspective, two wells are
seldom the same. Seismic data, or offset electrical data can be the
initial data source. Any predictions can then be verified or
improved upon, by data collected while drilling, by wireline at the
end of each hole section, or through testing or the occurrence of
specific drilling events. A good pressure report requires complete
analysis and evaluation of all data sources; it must be extremely
accurate, and all conclusions have to be substantiated. The new
pressure engineer will discover that theory can indeed be read from
a book and learnt in the classroom, but accurate pressure
engineering only comes with experience and exposure to different
pressure regimes, increasing the level of understanding of this
complex science. This manual therefore serves as a starter kit to
your challenging new position!
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2. PRESSURES & GRADIENTS
2.1 Hydrostatic Pressure Hydrostatic Pressure, at any given
vertical depth, is defined as the pressure exerted by the weight of
a static column of fluid. It is, therefore, pressure resulting from
a combination of the fluid density and the vertical height of the
fluid column. At any true vertical depth: Phyd = g h where Phyd =
hydrostatic pressure = fluid density h = vertical depth g =
conversion factor i.e. KPa = kg/m3 x 0.00981 x TVD(m) KPa = kilo
Pascals m = metres PSI = ppg x 0.052 x TVD(ft) PSI = pounds per
square inch ppg = pounds per gallon ft = feet
OVERBURDEN STRESS
Mud Hydrostatic Pressure
Formation Pore Fluid Pressure
Fracture Pressure
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Considering that water density will vary depending on the
concentration of salt, this formula gives the following example
range of normal hydrostatic gradients: - Hydrostatic Gradient is
the rate of increase of pressure with depth,
i.e. Hydrostatic Gradient = pressure/unit height = density x
conversion factor
Freshwater: Density = 8.33 ppg or 1.0 SG (1 gm/cc or 1000 kg/m3)
Hydrostatic Gradient = 8.33 x 0.052
= 0.433 psi/ft or = 1000 x 0.00981
= 9.81 KPa/m Brine: Density (e.g) = 9.23 ppg or 1.11 SG (1.11
gm/cc or 1108 kg/m3) Hydrostatic Gradient = 9.23 x 0.052
= 0.480 psi/ft or = 1108 x 0.00981
= 10.87 KPa/m The diagram below illustrates these two
hydrostatic gradients and the resulting pressures:
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At 3000m,
Freshwater, density 1000 kg/m3, exerts a pressure of 1000 x 3000
x 0.00981 = 29, 430 KPa
Saline water, density 1108 kg/m3, exerts a pressure of 1108 x
3000 x 0.00981 = 32, 608 KPa
3000m
PRESSURE (KPa)
DEPTH
9.81 KPa/m
10.87 KPa/m
29,430 32,608
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2.2 Formation Pressure Formation Pressure is defined as the
pressure exerted by the fluid contained within the pore spaces of a
sediment or rock. It is often termed Pore Pressure. In reality
therefore, formation pressure refers to the hydrostatic pressure
exerted by the pore fluid and is therefore dependent on the
vertical depth and the density of the formation fluid. Normal
formation pressure will be equal to the normal hydrostatic pressure
of the region and will vary depending on the type of formation
fluid. For example, in the northern North Sea, Normal pore fluid
density is equal to 1.04 SG (here, the formation connate water is
actually very close to the present day seawater density) This
density (8.66 ppg or 1040 kg/m3) gives a normal formation pressure
gradient of 0.450 psi/ft or 10.20 KPa/m: 8.66 ppg x 0.052 = 0.450
psi/ft 1040 kg/m3 x 0.00981 = 10.20 KPa/m In the Gulf of Mexico,
Normal pore fluid density is 1.07 SG, giving a normal pressure
gradient of 0.465 psi/ft or 10.53 KPa/m: 8.94 ppg x 0.052 = 0.465
psi/ft 1074 kg/m3 x 0.00981 = 10.53 KPa/m In other words, even
though the pressure gradients are different, both are normal
formation pressure gradients for the given regions. For a given
region then, If Formation Pressure = Hydrostatic Pressure, the
formation pressure is normal If Formation Pressure <
Hydrostatic, the formation is underpressured If Formation Pressure
> Hydrostatic, the formation is overpressured
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Pressure analysis, in any given region, therefore requires
knowledge of the normal fluid density and the resulting fluid
pressure. This can either be determined by laboratory analysis of
fluid samples, or by direct pressure measurements: Direct
measurement of the formation pressure can only be achieved where
the formation has sufficient permeability for the formation fluid
to reach equilibrium with a pressure gauge over a short period of
time. For low permeability formations, formation pressure can only
be estimated, and this forms a significant component of formation
pressure analysis. 2.2.1 Direct Pressure Measurements 2.2.1.1
Repeat Formation Test This is an open hole wireline tool that, per
run, allows the collection of two formation fluid samples and an
unlimited number of formation pressure measurements. A spring or
piston type mechanism holds a probe firmly against the borehole
wall and a hydraulic seal (from the drilling mud) is formed by
packer. The piston creates a vacuum in a test chamber, allowing
formation fluids to flow into sample chambers. The pressure during
the flow, and the subsequent build up, is measured. The initial
shut-in pressure is recorded. The test valve is opened to allow the
formation fluids to flow into the chamber the flow rate is recorded
as the chamber fills. Once full, the final shut-in pressure is
recorded. The build up or shut-in pressures may need to be
corrected to yield true formation pressure, since, particularly
with lower permeability formations, pressure build up may not have
stabilized. Tight formations, certainly, may result in the test
being aborted, because the fear of becoming stuck will discourage
most operators from allowing the test to continue for too long a
period. Seal failure may result if the probe cannot be properly
isolated from the mud (due to low permeability rocks, poor filter
cake development, or material stuck to the probe), so that pressure
does not increase much beyond the mud hydrostatic pressure. Higher,
or supercharged, formation pressure measurements may result where
low permeability zones have been invaded by higher pressured muds.
2.2.1.2 Drill Stem Test This is a production test of a reservoir
zone where hydrocarbons have been encountered. The test can be
performed in open or cased (i.e. production liners) holes.
Typically, the borehole is cased; the interval to be tested is then
sealed off with packers; the isolated zone can then be perforated
to allow formation fluids to flow to surface.
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The differences between starting and end pressures, during a
period of flow, yields information related to both the reservoir
productivity and the volume of hydrocarbons. When the DST tool is
in place, a packer (single or straddled packer arrangements may be
used to isolate a particular zone of interest) is set to form a
seal and the test can begin. Most DSTs incorporate 2, perhaps 3,
flow and shut-in periods. Formation Pressure is most accurately
estimated from the Initial Shut-In Pressure (ISIP) at the end of
the Initial Flow. This flow may last up to an hour and allows fluid
to flow to surface with the purpose of removing any pressure
pockets from the wellbore; cleaning out any mud filtrate fluids
that may have invaded the formation and removing mud from the
drillstem.. Subsequent flow periods will result in Final Shut-In
Pressures (FSIP) that will be slightly lower than the ISIP since
some of the reservoir fluids have already been produced, therefore
formation pressure is determined from the ISIP. Sometimes, a stable
ISIP may not be reached over the relatively short time before the
test is ended, so that the pressure has to be extrapolated. The
lower the permeability of the zone, the more likely this is. 2.2.2
Indirect Pressure Measurements 2.2.2.1 Kick Shut-In Pressures If
formation pressure exceeds the hydrostatic (or balancing) pressure
of the mud column, then, as long as fluids can flow, a kick will
result. Following a successful well control operation, the mud
hydrostatic pressure required to balance, or kill, the well, is
clearly equal to the actual formation pressure. An important
criterion for this estimation is knowledge of the exact depth of
influx, but, as long as this is known, the formation pressure can
be accurately, although indirectly, measured from the well shut-in
pressures. The shut-in (drill pipe) pressure is the additional
pressure, in addition to the mud hydrostatic pressure, required to
balance the higher formation pressure. At depth of influx: Mud
Hydrostatic Pressure + SIDP = Formation Pressure For example,
At 2500m (TVD), a kick is taken while drilling with a mud weight
of 1055 kg/m3. The well is shut in and a shut-in drillpipe pressure
of 1300 KPa is recorded.
Formation Pressure = (1055 x 2500 x 0.00981) + 1300 = 27, 174
KPa KMW = 27174 / (2500 x 0.00981) = 1108 kg/m3
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2.2.2.2 Connection Gases Connection gas is the term giving to a
gas response, of short duration, that occurs as a result of a
momentary influx of formation fluids into the wellbore, when the
annular pressure is momentarily reduced below the formation
pressure. This reduction may be as a result of simply turning the
pumps off so that the annular pressure drops from a circulating
pressure to static mud hydrostatic pressure, or, it may be as a
result of a pressure reduction caused by the act of lifting the
drillstring (swabbing). Knowledge of the balancing pressures (i.e.
circulating pressure, hydrostatic pressure, swab pressure) when a
connection gas is recorded, allows an indirect determination of
formation. Although an exact value cannot be determined, a
relatively small pressure range can be determined, and other than
the techniques detailed above, connection gases are the most
accurate determination of formation pressure while a well is being
drilled. Analysis of connection gases will be discussed in more
detail in Section 4.3.2.
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2.3 Fracture Pressure All materials, including rocks, have a
finite strength. Certainly, rock samples (recovered through coring
operations, for example) can be tested in laboratories for strength
by using conventional analysis. However, the in situ strength of a
rock exposed by a wellbore may vary from a laboratory
determination, because there are many other factors and stresses
involved. This makes the determination and analysis of fracture
pressure and gradient, very difficult at the wellsite. Simply,
Fracture Pressure can be defined as the maximum pressure that a
formation can sustain before its tensile strength is exceeded and
it fails. Factors affecting the fracture pressure include: Rock
type In-situ stresses Weaknesses such as fractures, faults
Condition of the borehole Relationship between wellbore geometry
and formation orientation Mud characteristics If a rock fractures,
a potentially dangerous situation exists in the wellbore. Firstly,
mud loss will result in the fractured zone. Depending on the mud
type and the volume lost, this can be extremely costly. Mud loss
may be reduced or prevented by reducing annular pressure through
reduced pump rates, or, more expensive remedial action may be
required, using a variety of materials to try and plug the
fractured zone and prevent further loss. Obviously, all of this
type of treatment is extremely damaging to the formation and is to
be avoided if at all possible. However, if mud loss is so severe,
then the mud level in the wellbore may actually drop, reducing the
hydrostatic pressure exerted in the wellbore. This may result in a
zone, elsewhere in the wellbore, becoming underbalanced and flowing
we now have an underground blowout! Knowledge of the fracture
gradient is therefore essential while planning and drilling a well,
yet there are only two ways of direct determination. The first is
an undesirable method if mud losses to the formation occur while
drilling, then one of two things has occurred. Either an extremely
cavernous formation has been penetrated, or a formation has been
fractured. Knowing the depth of the fractured zone and the
circulating pressure balancing the wellbore at the time of
fracture, will enable the fracture pressure to be calculated.
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2.3.1 Leak Off Tests This is a test performed at the beginning
of each hole section to determine the fracture pressure at that
point. At the end of a hole section, after logging has been
completed, casing will be run, and cemented in place, to isolate
all formations drilled. Before drilling ahead the next hole
section, it is critical to determine that the cement bond is strong
enough to prevent high pressure fluids, that may be encountered in
the next hole section, from flowing to shallower formations or to
surface. If as intended, cement holds the pressure exerted during
the test, then formation fracture will occur, under controlled
conditions. The formation at this depth, because it is the
shallowest point, will typically be the weakest formation
encountered in the next hole section, so that the fracture pressure
determined from the test will be the maximum pressure that can be
exerted in the wellbore without causing fracture. Two types of test
may actually be conducted: - A Formation (or Pressure) Integrity
Test (FIT or PIT) is often performed when the operator has a good
knowledge of the formation and fracture pressures in a given
region. With this test, rather than inducing fracture, the test is
taken to a pre-determined maximum pressure, one considered high
enough to safely drill the next hole section. A true Leak Off Test
(LOT) does involve the actual fracturing of the formation: - After
drilling through the casing shoe and cement, a small section
(typically 10m) of new hole is drilled beneath the cement. The well
is shut in, and mud pumped at a constant rate into the wellbore to
increase the pressure in the annulus. The pressure should increase
linearly and is closely monitored for signs of leak off, when the
pressure will drop. The pressure plot against time, or mud volume
pumped, shows that there are 3 principle stages to a complete Leak
Off Test. It must be the operator who makes the decision as to
which particular value is taken as the leak off pressure, but
obviously, it should be the lowest value. This way well be the
initial Leak Off Pressure, if the test hasnt been taken further to
cause complete rupture. If it has, then the Propagation Pressure is
likely to be the lowest, indicating that the formation has actually
been weakened as a result of the test.
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During the Leak Off Test, a combination of two pressures
actually induces the fracture: -
1. The Mud Hydrostatic Pressure 2. The Shut-in Pressure applied
by pumping mud into the closed well
Pfrac = HYDshoe + LOP Where LOP is the shut-in pressure applied
at surface, whether from a LOT or FIT For example: A Leak Off Test
is performed at a shoe depth of 1500m; the mudweight is 1045 kg/m3
and the recorded leak off pressure is 15000 KPa Pfrac = (1045 x
1500 x 0.00981) + 8000 = 23, 337 KPa Pfrac (emw) = 23337 / (1500 x
0.00981) = 1589 kg/m3
The pressure engineer should be aware, that although the Leak
Off Test is the only way of determine the fracture pressure, there
are certain circumstances that can lead to inaccuracy or
unreliability: -
Surface Shut In
Pressure
Mud Volume Pumped
Leak Off Pressure Slower pressure increase - reduce pump rate as
mud begins to inject into the formation
Rupture Pressure Complete and irreversible failure has occurred
when pressure drops - stop pumping
Propagation Pressure If pumping is stopped at the point of
failure, the formation may recover, but weakened
HYD
LOP
Fracture
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A Formation Integrity Test gives no determination of actual
fracture pressure, only an accepted maximum value for the drilling
operation. Although not providing accurate data, this test does
provide a safety margin.
Well consolidated formations are typically selected to set the
shoe this formation may not be
the weakest if subsequent unconsolidated formations are
encountered within a short interval from the shoe.
Apparent leak off may be seen in high permeability, or highly
vugular formations, without
fracture actually occurring.
Poor cement bonds may result in leak off through the cement,
rather than the formation.
Localized porosity or micro-fractures can result in lower
recorded fracture pressures.
Well geometry, in relation to horizontal or vertical stresses,
can also lead to deceptive fracture pressures, with different
results being produced, in the same formations, between vertical
and deviated wells.
Quantitative analysis of fracture gradients will be discussed in
Section 6.
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b
2.4 Overburden Stress At a given depth, the overburden pressure
is the pressure exerted by the cumulative weight of the overlying
sediments. The cumulative weight of the overlying rocks is a
function of the bulk density, the combined weight of matrix and
formation fluids contained within the pore space. Overburden
increases with depth, as bulk density increases and porosity
decreases. With increasing depth, cumulative weight and compaction,
fluids are squeezed out from the pore spaces, so that matrix
increases in relation to pore fluids. This leads to a proportional
decrease in porosity as compaction and bulk density increase with
depth. An average value of 2.31 gm/cc can be assumed to be a
reasonable average value of bulk density at depth (approximating to
an overburden gradient of 1.0 psi/ft), but more accurate
determinations should be made when more accurate measurements or
data becomes available. Typical overburden profiles, with depth,
are shown below: On land wells, the overburden at surface is
obviously zero, but will increase very rapidly, with depth, as
cumulative sediments and compaction increase. Offshore, the
gradient must be referenced to RKB or RT, as is practice, there
will be zero overburden between RKB and mean sea level, then the
weight of the water has to be considered in the overburden
gradient, which will start increasing from the seabed once
sediments are encountered.
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DATALOG: ABNORMAL FORMATION PRESSURE ANALYSIS, Version 2.1,
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2.4.1 Determination of Bulk Density Bulk density is a function
of the matrix density, porosity and pore fluid density, and can be
determined from the following formula: b = f + (1 )m = porosity,
value between 0 and 1 e.g. 12% = 0.12 f = pore fluid density m =
matrix density Accurate determination of the overburden gradient is
critical for accurate formation and fracture gradient calculations.
Naturally, then, the source of bulk density measurement, and the
quality of that data, is very important. It follows then, from the
bulk density equation, that porosity determination techniques such
as neutron porosity or sonic transit times can be used to provide
the porosity value. In practice, sonic logs are readily available
and can be used to determine the bulk density. Direct measurements
of bulk density are preferable, so density values from wireline
logs are extremely useful. However, this source of data is rarely
available for an entire well interval. Finally, direct measurements
from cuttings can be made while the well is being drilled. If no
offset data is available, or if there is doubt as to its accuracy,
then direct bulk density measurements should be taken from the
cuttings.
Rotary Kelly Bushing
Mean Sea Level
Sea Bed
OBG (EMW)
OBG
Depth Depth
Land Surface
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If, at the end of a hole section, better bulk density data can
be obtained from wireline, whether sonic or density, then
overburden calculations should be revised with the new data source.
2.4.1.1 Bulk Density from Cuttings Whilst drilling a well, the
Overburden Gradient can be directly calculated from surface bulk
density measurements. This would be done every 5 or 10m or whatever
the sample interval is. Obviously, the more frequent the
measurements, the more accurate the gradient will be. A simple
displacement technique can be used to determine bulk density, and,
as long as the engineer is precise and consistent, the data quality
is typically satisfactory for overburden calculations. The
technique is described below: -
Cuttings need to be washed (to remove drilling mud) and towel
dried to remove excess water. Obvious cavings should be removed so
that the sample selected is representative of the drilled
interval.
Accurately weigh a sample of 1 or 2 grams, for example.
Obviously, the larger the sample size, the smaller any error.
With distilled water, fill a 10cc graduated cylinder to exactly
5cc (so that there is sufficient
volume to submerge all the cuttings but not too much so that the
cylinder overflows). There will be a substantial meniscus on the
water surface, so be consistent and take the measurement either
from the top, or bottom, of the meniscus.
Carefully drop the cuttings
into the cylinder, being mindful of splashes and trapped
bubbles.
Lightly tap the side of the
cylinder to release any trapped bubbles and to help splashes, on
the side of the cylinder, run back into the water.
Read the new level of the
water, again being consistent with where, on the meniscus, you
take the reading.
5
6 1.1cc
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From these measurements: -
bulk density (SG or gm/cc) = weight of sample (gm) volume of
displaced water (cc) For example, if 2.00 gm of sample displaced
1.10 cc of distilled water: - Bulk density = 2.00 / 1.10 = 1.82
gm/cc Sources of error in this method include the following: -
Poor quality drilled cuttings Shale hydration or reactivity with
mud Sample not representative of drilled interval Inaccuracy in
weighing Inaccuracy/Inconsistency in determination of water
displacement Eye level not being parallel to water meniscus Trapped
bubbles, within bulk sample, increasing water volume
2.4.1.2 Bulk Density from Sonic Logs The Sonic log, since it is
a porosity log reflecting the proportions of matrix to fluid, can
be used to derive bulk density using the following formulae (Agip
adapted from Wyllie, 1958): -
For consolidated rocks, b = 3.28 T 89
For unconsolidated rocks, b = 2.75 2.11 (T 47) (T + 200) where b
= gm/cc T = formation transit time (actual sonic sec/ft)
47 = default matrix travel time 200 = default fluid travel
time
Rather than the default 47, the following formation values for
the matrix transit time can be used: - Dolomite 43.5 Limestone 47.6
Sandstone 51 (consolidated) to 55 (unconsolidated) Anhydrite 50
Salt 67 Claystone 47
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2.4.2 Calculation of Overburden Gradient Knowledge of the
overburden gradient is essential for accurate formation pressure
and fracture gradient calculations. As stated previously, the
overburden stress, exerted at any given depth, is a function of the
bulk density of the overlying sediments. Hence, whatever the source
of the bulk density data, calculation of the overburden gradient is
based on the average bulk density for a given depth interval:
Overburden S = b x TVD TVD = metres 10 S = kg/cm2 b = average bulk
density g/cm3 S = b x TVD x 9.81 TVD = m S = Kpa b = g/cm3 S = b x
TVD x 0.433 TVD = ft S = psi b = g/cm3
From the average bulk density, calculate the overburden pressure
for a given interval
Calculate the cumulative overburden pressure for that overall
depth
Calculate the overburden gradient Three examples are
illustrated, using the different units of measurement.
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Example 1
Interval Thickness Av b Interval Cumul OBG Grad EMW OB Press OB
Pres
(m) (gm/cc) (KPa) (KPa) (KPa/m) (kg/m3)
0 - 50 50 1.25 613 613 12.26 1250 50 - 200 150 1.48 2178 2791
13.95 1422 200 - 300 100 1.65 1619 4410 14.70 1498 300 - 400 100
1.78 1746 6156 15.39 1569
For the interval 0 to 50m Overburden Pressure = 1.25 x 50 x 9.81
= 613 KPa Cumulative Pressure = 0 + 613 = 613 KPa Overburden
Gradient = 613 / 50 = 12.26 KPa/m O/B Gradient EMW = 12.26 /
0.00981 = 1250 kg/m3 emw For the interval 50 to 200m Overburden
Pressure = 1.48 x 150 x 9.81 = 2178 KPa Cumulative Pressure = 0 +
613 + 2178 = 2791 KPa Overburden Gradient = 2791 / 200 = 13.95
KPa/m O/B Gradient EMW = 13.95 / 0.00981 = 1422 kg/m3 emw
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Example 2
Interval Thickness Av b Interval Cumul OBG Grad EMW OB Press OB
Pres (m) (gm/cc) (kg/cm2) (kg/cm2) (kg/cm2/10m) (kg/m3) (~
gm/cc)
0 - 100 100 1.35 13.5 13.5 1.35 1350 100 - 300 200 1.65 33.0
46.5 1.55 1550 300 - 450 150 1.78 26.7 73.2 1.63 1630 450 - 700 250
1.85 46.3 119.5 1.71 1710
For the interval 0 to 100m Overburden pressure = (1.35 x 100) /
10 = 13.5 kg/cm2
Cumulative pressure = 0 + 13.5 = 13.5 kg/cm2 Overburden gradient
= (cumulative x 10) /(0 + 100) = (13.5 x 10) / 100 = 1.35
kg/cm2/10m
O/B Gradient EMW = 1.35 x 1000 = 1350 kg/m3
NOTE 1 kg/cm2/10m = 1 gm/cc = 1000 kg/m3 emw
For the interval 100 to 300m Overburden pressure = (1.65 x 200)
/ 10 = 33.0 kg/cm2 Cumulative pressure = 0 + 13.5 + 33.0 = 46.5
kg/cm2 Overburden gradient = (46.5 x 10) / (0 + 100 + 200) = 1.55
kg/cm2/10m O/B Gradient EMW = 1.55 x 1000 = 1550 kg/m3
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Example 3
Interval Thickness Av b Interval Cumul OBG Grad EMW OB Press OB
Pres (ft) (gm/cc) (psi) (psi) (psi/ft) (ppg)
0 - 50 50 1.10 23.8 23.8 0.476 9.15 50 - 150 100 1.46 63.2 87.0
0.580 11.15 150 - 350 200 1.72 148.9 235.9 0.674 12.96 350 - 500
150 1.80 116.9 352.8 0.706 13.58
For the interval 0 to 50ft Overburden Pressure = 1.10 x 50 x
0.433 = 23.8 psi Cumulative Pressure = 0 + 23.8 = 23.8 psi
Overburden Gradient = 23.8 / 50 = 0.476 psi/ft O/B Gradient EMW =
0.476 / 0.052 = 9.15 ppg emw For the interval 50 to 150 ft
Overburden Pressure = 1.46 x 100 x 0.433 = 63.2 psi Cumulative
Pressure = 0 + 23.8 + 63.2 = 87.0 psi Overburden Gradient = 87.0 /
150 = 0.58 psi/ft O/B Gradient EMW = 0.58 / 0.052 = 11.15 ppg
emw
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2.5 Balancing Wellbore Pressures This section has, so far,
detailed the lithological pressures and gradients that are
encountered when drilling a well. It is now important to detail the
wellbore pressures that act against the lithological pressures.
2.5.1 Mud Hydrostatic At the beginning of the section, Hydrostatic
Pressure was defined as the pressure exerted at a given depth by
the weight of a static column of fluid. It therefore follows, that
when a given drilling fluid, or mud, fills the annulus, the
pressure at any depth is equal to the Mud Hydrostatic Pressure. At
any depth: - HYDmud = mudweight x TVD x g PSI = PPG x ft x 0.052
KPa = kg/m3 x m x 0.00981 This will tell us the balancing pressure,
in the wellbore, when no drilling activity is taking place and the
mud column is static.
emw
depth
FP - Formation Pressure Pfrac - Fracture Pressure OB -
Overburden Gradient
FP Pfrac OB
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As soon as any movement of the mud is initiated, then frictional
pressure losses will result in either an increase, or decrease, in
the balancing pressure, depending on the particular activity, which
is taking place. At all times, it is important to know what the
annular balancing pressure is, and the relationship with the
lithological pressures acting against them: -
If formation pressure is allowed to exceed the wellbore
pressure, then formation fluids can influx into the wellbore and a
kick may result.
If the wellbore pressure is allowed to exceed the fracture
pressure, then fracture can result,
leading to lost circulation and possible blowout. 2.5.2
Equivalent Circulating Density During circulation, the pressure
exerted by the dynamic fluid column at the bottom of the hole
increases (and also the equivalent pressure at any point in the
annulus). This increase results from the frictional forces and
annular pressure losses caused by the fluid movement. Knowing this
pressure is extremely important during drilling, since the
balancing pressure in the wellbore is now higher than the pressure
due to the static mud column. Higher circulating pressure will
result in: -
Greater overbalance in comparison to the formation pressure
Increased risk of formation flushing More severe formation invasion
Increased risk of differential sticking Greater load exerted on the
surface equipment
The increased pressure is termed the Dynamic Pressure or Bottom
Hole Circulating Pressure (BHCP). BHCP = HYDmud + Pa where Pa is
the sum of the annular pressure losses When this pressure is
converted to an equivalent mudweight, the term Equivalent
Circulating Density is used.
ECD = MW + Pa (g x TVD) The weight of drilled cuttings also
needs to be considered when drilling. The weight of the cuttings
loading the annulus, at any time, will act, in addition to the
weight of the mud, to increase the pressure at the bottom of the
hole.
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Similar to the increase in bottom hole pressure when circulating
(ECD), pressure changes are seen as a result of induced mud
movement, and resulting frictional pressures, when pipe is run in,
or pulled out, of the hole. 2.5.3 Surge Pressures Surge Pressures
result when pipe is run into the hole. This causes an upward
movement of the mud in the annulus as it is being displaced by the
drillstring (as seen by the mud displaced at surface into the pit
system), resulting in frictional pressure.
This frictional pressure causes an increase, or surge, in
pressure when the pipe is being run into the hole. The size of the
pressure increase is dependent on a number of factors, including
the length of pipe, the pipe running speed, the annular clearance
and whether the pipe is open or closed. In addition to the
frictional pressure, which can be calculated, it is also reasonable
to assume that fast downward movement of the pipe will cause a
shock wave that will travel through the mud and be damaging to the
wellbore. Surge pressures will certainly cause damage to
formations, causing mud invasion of permeable formations, unstable
hole conditions etc.
The real danger of surge pressure, however, is that if it is too
excessive, it could exceed the fracture pressure of weaker or
unconsolidated formations and cause breakdown. It is a common
misconception, that if the string is inside casing, then the open
wellbore is safe from surge pressures. This is most definitely not
the case! Whatever the depth of the bit during running in, the
surge pressure caused by the mud movement to that depth, will also
be acting at the bottom of the hole. Therefore, even if the string
is inside casing, the resulting surge pressure, if large enough,
could be causing breakdown of a formation in the open wellbore.
This is extremely pertinent when the hole depth is not too far
beyond the last casing point! Running casing is a particularly
vulnerable time, for surge pressures, due to the small annular
clearance and the fact that the casing is closed ended. For this
reason, casing is always run at a slow speed, and mud displacements
are very closely monitored. 2.5.4 Swab Pressures Swab Pressures,
again, result from the friction caused by the mud movement, this
time resulting from lifting the pipe out of the hole. The
frictional pressure losses, with upward pipe movement, now result
in an overall reduction in the mud hydrostatic pressure.
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The mud movement results principally from two processes: -
1. With slower pipe movement, an initial upward movement of
the
mud surrounding the pipe may result. Due to the muds viscosity,
it can tend to cling to the pipe and be dragged upward with the
pipe lift.
2. More importantly, as the pipe lift continues, and especially
with
rapid pipe movement, a void space is left immediately beneath
the bit and, naturally, mud from the annulus will fall to fill this
void.
This frictional pressure loss causes a reduction in the mud
hydrostatic pressure. If the pressure is reduced below the
formation pore fluid pressure, then two things can result: -
1. With impermeable shale type formations, the underbalanced
situation causes the formation to
fracture and cave at the borehole wall. This generates the
familiar pressure cavings that can load the annulus and lead to
pack off of the drill string.
2. With permeable formations, the situation is far more critical
and, simply, the underbalanced situation
leads to the invasion of formation fluids, which may result in a
kick. In addition to these frictional pressure losses, a piston
type process can lead to further fluid influx from permeable
formations. When full gauge tools such as stabilizers are pulled
passed permeable formations, the lack of annular clearance can
cause a syringe type effect, drawing fluids into the borehole. More
than 25% of blowouts result from reduced hydrostatic pressure
caused by swabbing. Beside the well safety aspect, invasion of
fluids due to swabbing can lead to mud contamination and
necessitate the costly task of replacing the mud. Pressure
changes due to changing pipe direction, eg during connections, can
be particularly
damaging to the well by causing sloughing shale, by forming
bridges or ledges, and by causing hole fill requiring reaming.
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2.5.5 Kick Tolerance
From the previous sections, it is clear to see that the mud
weight must be sufficient to exert a pressure that will balance the
formation pressure and prevent a kick, but it cannot be so high
that the resulting pressure would cause a formation to fracture.
This would lead to lost circulation (mud being lost to the
formation) in the fractured zone. This, in turn, would lead to a
drop in the mud level in the annulus, reducing the hydrostatic
pressure throughout the wellbore. Ultimately then, with reduced
pressure in the annulus, a permeable formation at another point in
the wellbore may begin to flow. With lost circulation at one point
and influx at another, we now have the beginnings of an underground
blowout!
A critical condition exists should the wellbore has to be shut
in. While drilling, high formation pressures can be safely balanced
by the mudweight. However, if a kick is taken (either through a
further increase in formation pressure, or through a pressure
reduction cause by swabbing, for example), then the well would have
to be shut in. If the pressure caused by the mudweight is too high,
then weaker formations at the shoe may fracture when the well is
shut in. This situation would be worsened if higher shut-in
pressures are required to balance low density influxes, especially
expanding gas! KICK TOLERANCE is the maximum balance gradient (i.e.
mudweight) that can be handled by a well, at the current TVD,
without fracturing the shoe should the well have to be shut in.
KICK TOLERANCE = TVDshoe x (Pfrac MW) TVDhole Where Pfrac =
fracture gradient (emw) at the shoe MW = current mudweight If the
mudweight, that is required to balance the formation pressures
while drilling, would result in shoe fracture during well shut in,
then a deeper casing shoe (with greater fracture pressure) must be
set. In order to account for a gas influx, the formula is modified
as follows: -
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KT = [TVDshoe x (Pfrac MW)] - [influx height x (MW gas density)]
TVDhole TVDhole The method illustrated is based on three
criteria:
A maximum influx height and volume (zero kick tolerance) Point X
A typical or known gas density (from previous well tests for
example)
The maximum kick tolerance (liquid influx with no gas) Point
Y
This defines limits on a graphical plot, which provides easy
reference to this important parameter. The values are determined as
follows: Maximum Height = TVDshoe x (Pfrac MW) MW gas density If
gas density is unknown, assume 250 kg/m3 (0.25 SG or 2.08ppg)
Maximum Influx Volume is determined from the maximum height and
the annular capacities this defines Point Y on the graph.
Maximum KT, as shown before, = TVDshoe x (Pfrac MW) TVDhole This
defines Point X on the graph, a liquid influx without any gas. The
graph is completed by dividing it into the different annular
sections covered by the influx, i.e. in the event that there are
different drill collar sections, or if the influx passes above the
drill collar section, or even if the influx passes from open hole
to casing. This is necessary since the same volume of influx will
have different column heights in each annular section.
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2.5.5.1 Kick Tolerance, worked example Using the following well
configuration: Casing Shoe = 2000m Hole Depth = 3000m Pfrac at shoe
= 1500 kg/m3 emw Current MW = 1150 kg/m3 Drill Collar length = 200m
Annular Cap = 0.01526m3/m (216mm open hole, 165mm drill collars)
Annular Cap = 0.02396m3/m (216mm open hole, 127mm drillpipe) Gas
Density = 250 kg/m3 Maximum Height = TVDshoe x (Pfrac MW) = 2000
(1500 1150) = 777.8m MW gas density 1150 250 Maximum Volume,
determined from 200m around the drill collars, and 577.8m around
drillpipe: DC = 200 x 0.01526 = 3.05m3 DP = 577.8 x 0.02396 =
13.84m3 Max Vol = 3.05 + 13.84 = 16.89m3 Maximum KT = TVDshoe x
(Pfrac MW) = 2000 (1500 1150) = 233.3 kg/m3 TVDhole 3000 Therefore,
Point X = 16.7m3, Point Y = 233 kg/m3 Now, determine the break
point of the graph, for the drill collar / drill pipe annular
sections:
To do this, calculate the KT related to a 3.05m3 gas influx,
which would reach the top of the 200m length of drill collars:
KT = [TVDshoe x (Pfrac MW)] - [influx height x (MW gas
density)]
TVDhole TVDhole = 2000 (1500 1150) - 200 (1150 250)
3000 3000
= 173.3 kg/m3 Therefore, 3.05m3 and 173.3 kg/m3 define the break
point on the graph. The graph can now be plotted, as follows:
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From this graph, the following information can be determined:
For a liquid influx, with no gas:
The kick tolerance is 233 kg/m3 above the present mudweight.
This would mean that the maximum formation pressure that can be
controlled, by well shut-in, without resulting in fracture, is 1383
kg/m3 (1150 + 233).
If formation pressures greater than this are anticipated, then a
new casing shoe would have to be
set. Lighter and expanding gas changes this scenario
dramatically:
If more than 16.7 m3 of gas was allowed into the annulus, there
is no kick tolerance on well shut-in, the shoe would fracture!
Operators will often work on an acceptable maximum kick influx
to determine kick tolerance:
For example, a 10 m3 gas influx would give a kick tolerance of
86 kg/m3 above the present
mudweight.
0 2 3.05 4 6 8 10 12 14 16 18 20
240
200
173 160
120
80
40
0
KT kg/m3
Influx Volume m3 X
Y Drill Collars Drill Pipe
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This can be verified with the formula:
Of the 10m3, 6.95m3 would be around the drillpipe annular
section, since 3.05m3 fill the drill collar section:
Height around DP = 6.95 / 0.02396 = 290m Height around DC = 200m
Total Height = 490m KT = 2000 (1500 1150) - 490 (1150 250) 3000 =
86.3 kg/m3
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2.6 Summary of Formulae Hydrostatic Formula: Pressure = Density
x TVD x constant PSI = PPG x ft x 0.052 KPa = kg/m3 x m x 0.00981
PSI = g/cc x ft x 0.433 Conversions: kg/m3 = g/cc x 1000 kg/m3 =
PPG x 1000 x (0.052/0.433) Oil Density g/cc = 141.5 / (API + 131.5)
g/cc = (psi/ft) / 0.433 Formation Pressure = mud hydrostatic +
shut-in drillpipe pressure
From a kick, if depth of influx is known Fracture Pressure = mud
hydrostatic (shoe) + Leak Off Pressure
From a Leak Off Test after drilling out casing Overburden Stress
S kg/cm3 = b (g/cc) x TVD(m)
10
KPa = b (g/cc) x TVD(m) x 9.81 PSI = b (g/cc) x TVD(ft) x 0.433
Equivalent Circulating Density ECD = MW + Pa (annular pressure
losses) (g x TVD)
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Kick Tolerance (assuming influx without gas) = TVDshoe x (Pfrac
MW) TVDhole Kick Tolerance (assuming given volume of known gas
density)
= [TVDshoe x (Pfrac MW)] - [influx height x (MW gas density)]
TVDhole TVDhole Annular Capacity m3 / m = 0.785 x (Dh2 - ODpipe2)
diameters in metres bbls / ft = (Dh2 - ODpipe2) / 1029.46 diameters
in inches Typical Influx Densities Gas 2.08 ppg 250 kg/m3 Oil 7.08
ppg 850 kg/m3 Freshwater 8.33 ppg 1000 kg/m3 Saltwater 8.66 ppg
1040 kg/m3
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3 OCCURRENCES OF ABNORMAL FORMATION PRESSURE
3.1 Underpressured formations Underpressure is rarely given the
same attention as overpressure, but encountering such zones with an
overbalanced mud system can certainly lead to problems, and
possible loss of hydrostatic control with catastrophic
consequences:
Mud invasion Formation damage Differential sticking Lost
circulation Formation fracture Loss of hydrostatic pressure
Underground blowout
3.1.1 Reductions in Confining Pressure or Fluid Volume Imagine
an enclosed system containing a given fluid volume; if either the
pressure imposed on that system, or the actual fluid volume, is
reduced, then there is the potential for that system to become
sub-normally pressured. Such situations include:
Depletion of water (aquifers) or hydrocarbon reservoirs through
production. Removal of overburden pressure, through erosion, may
lead to an expansion of pore space in
more elastic clays. If there is communication with interbedded
or lenticular sands, for example, fluids will be drawn away from
the sands, leading to a depletion in pressure.
3.1.2 Apparent Underpressure Postions of the water table, or
point of outcrop, can lead to lower than expected fluid columns,
which, to all intents and purposes, appear underpressured in
relation to the drilling process and mud column.
Water reservoir outcropping at a lower altitude than the
elevation penetrated during drilling. Therefore, the part of the
formation penetrated will be above the water table and at
atmospheric pressure.
WT
Atmospheric pressure
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The position of the water table in relation to the land surface.
If the location of the well is topographically above the water
table, the height of the fluid column will be less than the actual
total depth. Therefore the hydrostatic pressure caused by the fluid
column would be less than expected for a complete water column.
Both of these situations could be common in uplifted
regions.
Large gas columns can also result in underpressured formations,
since the low density gas reduces the effective hydrostatic
pressure, in comparison to a liquid column.
WT Fluid column
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3.2 Overpressure Requirements 3.2.1 Overpressure Model Over the
years, many models concerning the occurrence of abnormal formation
pressures have been proposed. A very simple definition, as detailed
in Section 2.2, is that overpressure is any formation pressure that
exceeds the hydrostatic pressure, which is exerted by the formation
water normal for that region. This concept proposes that any
subsurface pressure can be compared to the pressure exerted by a
formation water column that exists from surface to the same depth.
What virtually all mechanisms of overpressure have in common, is
that the zone in question has retained, or contains, an abnormal
volume of formation water, leading to an inequilibrium. What this
suggests is that, whatever the mechanism leading to excessive pore
fluid volume, overpressure results from the inability of the
retained fluids to escape at a rate which will maintain a pressure
equilibrium with a water column that extends to surface. The
following requirements are after the model proposed by Swarbrick
and Osborne, 1998. This brings in two very important factors in the
generation of overpressured systems, namely permeability and time.
A third factor in the occurrence of overpressure is the fluid type
and properties such as viscosity, which also have a determining
effect on fluid flow. 3.2.1.1 Permeability Given communication,
fluids will always flow from a zone of higher pressure to a zone of
lower pressure. Permeability relates the rate at which a given
fluid will flow, per unit time, along the line of such a pressure
drop. Permeability is measured in Darcys (or rather, milli-Darcies)
and is a function of the rock properties such as grain size, grain
shape, and tortuosity (irregularity of flow paths) and also the
fluid properties (i.e. density and viscosity). The degree of
permeability will be a determining factor in how easy initial pore
fluids can escape during a rocks history.
Overpressure resulting from fluid retention will obviously be
more common in low permeability, non-reservoir type lithologies,
such as clay.
Overpressure resulting from fluid retention in permeable,
reservoir type rocks, will be
determined by the lack of permeability (i.e the quality of seal)
in the overlying and surrounding rocks.
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3.2.1.2 Time As stated in section 3.2.1, overpressure, by
definition, is a zone which is in a state of inequilibrium. All
conditions of inequilibrium, with suitable conditions, will, over
time, stabilize to a condition of equilibrium. Geological time is
more than sufficient for such changes in equilibrium to change, and
given even the smallest degree of permeability, fluids will
redistribute if there is a pressure gradient. Over the course of a
formations history, therefore, the degree of overpressure will
decrease as fluids, and pressure, redistribute to surrounding
zones. The only exception is if there is an absolute perfect seal,
zero permeability, preventing fluids from redistribution, but,
again, a perfect seal is very difficult to maintain over geological
time given the overburden, tectonic, and other stresses that
continually act on any given zone. 3.2.1.3 Fluid Type The density
of formation waters, in other words the amount of dissolved salts,
determines the pressure gradient in any given region. Even though
individual zones may have varying degrees of salinity within their
pore, or connate, water, and thus varying pressure gradients, the
pressure would still be regarded as normal. Where, however,
chemical processes (osmosis) lead to an exchange of dissolved salts
between fluids, the resulting change in density and pressure would
be regarded as a deviation from the normal formation pressure
gradient. More importantly, in terms of the overpressure model, the
fluid type determines the flow properties of that fluid and
therefore relates to permeability and time in the occurrence of
overpressured zones. For example, the presence of oil and gas,
producing a multi-component fluid, reduces the relative
permeability of the original pore fluid. This will actually enhance
the effective seal of surrounding rocks and increase the likelihood
of overpressure resulting. Specific flow characteristics not only
vary with viscosity or multi-phase fluids, but on a number of
properties, such as temperature, hydrocarbon composition, degree of
saturation, phase, etc. As can be seen, the three criteria for the
occurrence of overpressure, permeability, time and fluid type, are
all interactive and/or interdependent. The actual occurrence of
overpressure, the degree of overpressure, and how quickly it can
build or dissipate, depends on the particular environment or cause
of the abnormal volume of pore fluid. In other words, for
overpressure to occur, there has to be a specific mechanism that
generates the excess fluid in the first instance. These will be
discussed in section 3.3.
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3.3 Causes Of Overpressure As we did when looking at the causes
of underpressured zones, in section 3.1.1, imagine an enclosed unit
of rock containing a given volume of pore fluid. Any reduction in
the volume of that unit of rock, or any increase in the volume of
enclosed pore fluid, will lead to fluid being necessarily expelled.
Now that we have seen the principles of permeability, fluid type,
and time, and the role they play, if the required fluid expulsion
is not achieved at a rate that will maintain a pressure
equilibrium, then overpressure will result. The specific mechanisms
that may result in this can be divided into the following 5
categories: -
1. Overburden effect 2. Tectonic stresses 3. Increases in fluid
volume 4. Osmosis 5. Hydrostatic
3.3.1 Overburden Effect In terms of our two causes, reduction in
rock/pore volume or increase in fluid, this obviously fits into the
reduction in pore volume category and is common in deltaic
environments and subsiding sedimentary basins, evaporite deposits,
etc. As sedimentation and burial increases the vertical thickness
of overlying sediments, vertical loading (i.e. overburden) results.
Vertical loading during burial results in a normal compaction of
the sediments, and necessarily requires the expulsion of pore
fluids as pore volume is reduced. Typically, a slow burial rate
will result in a normal compaction rate with fluids being expelled
allowing pore volume to decrease as overburden increases. A normal
compaction rate will result in a normal fluid pressure
gradient.
SLOW BURIAL
NORMAL COMPACTION
EFFICIENT DE-WATERING
NORMAL PRESSURE
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However, if normal compaction and normal de-watering does not
take place, then overpressure can occur as a result of fluids being
retained by the sediments. Clays are more prone to overpressure
from this mechanism due to the following mechanical properties:
Higher initial pore fluid volume, up to 70 or 80% of the total
volume. This compares to sands which may have around 40% initial
pore volume.
Higher rate of compaction.
Continued compaction (to around 5% pore volume) to greater
depths (~ 5km), requiring a huge
volume of water to be expelled over a long period of time. This
compares to sands, which may have a pore volume reduction to 15
20%, but do not continue compaction to the same depths as
clays.
Therefore, with higher normal fluid volumes to begin with, and
longer compaction periods requiring continued fluid expulsion,
there is greater potential for undercompaction to occur.
In addition, during normal burial and diagenesis, additional
fluid volume is generated by changes in the clay chemistry,
increasing the amount of de-watering that is required to maintain
normal pressure.
If there is not equilibrium between loading and compaction, and
the fluid is not expelled at the required rate during burial, then
undercompaction results and the zone will be overpressured. There
are two principle causes of this inequilibrium:
1. Rapid burial so that there is insufficient time for the large
fluid volume, resulting from the high sedimentation rate, to be
expelled. Rapid burial rates are certain to cause overpressure when
combined with low permeability sediments.
2. Drainage restrictions preventing normal fluid expulsion.
Low permeability Lack of sandy or silty layers facilitating
de-watering Impermeable layers, such as evaporates or carbonates,
creating a barrier to fluid
expulsion
Where there is incomplete de-watering of shales, within a
shale-sand sequence, porosity and pressure is often seen to be
higher towards the centre of the clay sections, and lower towards
the contact with the normally pressured sands (Magara, 1974).
Pressure in shale
Normal pressure
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3.3.2 Tectonic Loading In the previous section, the compaction
of rocks, and reduction in pore space resulting from vertical
loading, was discussed. In the same way, tectonic stresses may lead
to horizontal compression and associated reduction in pore volume.
This is not well documented or proven and, to be a cause of
overpressure, would tolerate none of the normal fracturing or
faulting (facilitating fluid expulsion) that would normally be
associated with such tectonic stresses. Tectonic activity, on the
other hand, caused by uplift, faulting or folding of rocks, can
lead to the occurrence of overpressure, through hydrodynamic
activity and the modification and redistribution of fluids and
pressures. Tectonic stresses may actually restrict fluid expulsion,
yet conversely, they can result in fracturing that will facilitate
fluid drainage. If a formation is uplifted, yet remains sealed and
incurs no fracturing, it will retain its original (deeper) fluid
pressure at the shallower depth. This retained palaeopressure will
be overpressured in comparison to the surrounding formations.
3.3.2.1 Faulting Faulting can lead to the occurrence of
overpressured formations through forming an effective seal or,
conversely, acting as a drain: - Faults and fractures may provide a
conduit
allowing deeper fluid pressures to be released to shallower
formations. Thus, pressure in the deeper formation is depleted and
the pressure in the shallower formation is charged, until
equilibrium is reached.
Permeable and impermeable layers may be juxtaposed
by a fault restricting normal fluid migration, so that
palaeopressure is retained.
Fluid drainage
Uplifted & sealed
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3.3.2.2 Deltaic Environments Naturally, sedimentation and
subsistence are important components to a deltaic environment in
the formation of sedimentary basins. Where sedimentation rates are
fast and where drainage is poor, sediments will not dewater
effectively and water-logged, overpressured zones will result.
Growth faults and shale diapirism are two structural situations,
common to deltaic environments, that can result in
overpressure.
Shale diapirism, intrusive flow from underlying layers, results
in domes, which are always undercompacted and overpressured. Many
characteristics of shale (and salt) domes can result in further
zones of overpressure and these will be detailed in section
3.3.2.3.
Growth faults have a curved fault plane, steep in the upper
part, and shallower at the base.
Basement tectonics, slumping, diapirism, overburden effect, may
all be responsible, in part or whole, in the generation of growth
faults.
Sediments on the downdip of the fault will thicken and form an
anticlinal rollover against the fault plane. This is often the site
for hydrocarbon accumulations and the reason for drilling in these
areas. At the base of the growth fault, on the updip side, a ridge
of undercompacted and overpressured shale often forms where
dewatering is ineffective as the sediments rapidly accumulate and
fill the basin.
Sediment influx
Overpressured Shale
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3.3.2.3 Diapirism/Domes As said in the previous section,
diaprisim is where there is intrusive flow of salt or shale, into
overlying sediments, forming domes, which can be on a massive
scale. Shale diapirisim will always result in a mass of
undercompacted and overpressured shale, but both shale and salt
domes have many mechanisms that can result in overpressured zones.
Salt is completely impermeably, thus providing perfect seals for
fluid pressures as well as hydrocarbons. These are illustrated
below: - As detailed in section 3.3.1, remember that salt or
evaporite layers within a sedimentary sequence, provide a
completely impervious boundary to vertical fluid expulsion
resulting in underlying, overpressured clays.
Isolated, uplifted rafts, perfectly sealed in the salt, retain
palaoepressure. In addition, multi-directional stresses act on the
raft.
Uplifted and pierced layers are sealed against the dome
(especially salt). Associated faulting can produce additional seals
as well as hydrocarbon traps
Pressure transfer from undercompacted shale dome, to adjacent,
pierced, permeable formations Osmotic effects where formations
adjacent to salt domes have raised
Uplifted zones, retaining palaeopressure from depth
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3.3.3 Increases in Fluid Volume As already detailed, within a
confined unit of rock, with a given pore volume, any increase in
fluid volume within that confined space will generate an increase
in pressure. There are many mechanisms that may lead to this volume
increase; some are well understood, others are not; some are proven
and accepted, others still disputed! 3.3.3.1 Clay Diagenesis As
young sediments are undergoing diagenesis during early burial
stages, clay mineralogy changes (largely due to increasing
temperature) and, as a result, water is generated. Smectite clay is
chemically altered, during diagenesis, to illite. Many clay basins
show this gradual transformation, with depth, of smectite to
illite. Water is absorbed into the lattice structure of smectite,
but illite does not have the same capacity to absorb water. Thus,
lattice-bound water released during the chemical transformation of
smectite, remains free water. In terms of generating overpressure,
there are two important things to note:
1. The release of lattice-bound water is effectively a volume
increase of water, a cause of overpressure in itself. Although
there is some question as to the precise volume increase, many
overpressured zones coincide with the smectite-illite transition
(Bruce, 1984).
2. During the early stages of diagenesis, when this water is
being released, the clays are undergoing
normal burial, de-watering and compaction. As mineralogy changes
and water is released, the clay structure becomes more compressible
so that the released water is adding to the volume of water that
has to be expelled to maintain equilibrium with the vertical
loading and subsidence rate. As described in section 3.3.1, any
inhibition to de-watering, now with a larger volume of water, will
result in overpressure.
There are additional points to note regarding clay diagenesis
and mineral transformation:
As smectite is transformation to illite, silica is being
produced, and this could effectively reduce any permeability and
inhibit the de-watering process and release of water.
As well as being a possible cause of overpressure, the situation
could be reversed, in that,
overpressured zones could actually enhance or facilitate the
clay alteration. Temperature is the main cause of the mineralogy
change, and the higher temperature gradients could well lead to, or
increase, the transformation of smectite to illite. The
overpressure zone could easily, therefore, be subject to a further
rise in formation fluid pressure if the additional water is
retained.
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3.3.3.2 Gypsum Dehydration Similar to the clay diagenesis just
described, this is, again, a mineralogy change resulting from
relatively shallow burial temperatures. As gypsum transforms to
anhydrite, bound water is again released and capable of generating
considerable formation pressures if it is not expelled. Where salt
is associated with the evaporites, the temperature required for
transformation is lowered further (25C, Kern & Weisbrod, 1964)
so that water is released at very shallow depths, virtually at
surface. In this situation, it is perhaps more likely that the
excess water will be expelled, unless associated salt provides an
impervious barrier. 3.3.3.3 Hydrocarbon or Methane Generation
Biogenic Methane Although seals are rarely perfect, so that gas
will typically migrate harmlessly to surface, shallow gas pockets
can be encountered while drilling. This poses a great danger since
very little warning time is given before gas from a penetrated
pocket reaches surface. This methane gas is generated from the
bacterial decay of organic material trapped within sediments, at
shallow depths. If the sediments are isolated, then the volume
expansion associated with the production of methane can generate
overpressure. Hydrocarbon Generation from Kerogen With deeper
burial and higher temperatures (2 to 4km, 70 to 120 C, Tissot &
Welte, 1984), as kerogen passes through the oil window, kerogen
matures to generate oil and gas. The associated volume increase is
not understood or accurately known, but it may result in a pressure
increase, since there has to be some sort of pressure increase to
initiate the primary migration of hydrocarbons. Thermal Cracking
Beyond the oil window, at greater depths and temperatures (3 to
5.5km, 90 to 150C, Barker, 1990), thermal cracking takes place,
where oil is broken down to lighter hydrocarbons and ultimately,
methane (often referred to as dry gas). Again, t