Mass Power
06.01 Abnormal / Subnormal pressure
So far it has been assumed that there is a direct proportional relation between formation pressure and fluid density and true vertical depth from the surface.
That means that the formation fluid pressure is only affected by the fluid density and from the true vertical depth.
The influence of the overlying rock formations has so far not been considered.
The reason is that in case of a permeable and porous formation system every single rock particle rests upon or leans up against other particles just below and to the side of it.
Therefore the rock structure supports its own weight, and regardless of depth does not affect
DEPTH
0
2500
5000 1000 2000 3000 4000 5000
PRESSURE
1 Gas grad. 0.07 psi/ft 2 Oil grad. 0.30 psi/ft
3 Fresh W. grad 0.433 psi/ft
4 Salt W. grad 0.465 psi/ft
5 10 ppg grad. 0.52 psi/ft
6 15 ppg grad. 0.7785 psi/ft
7 21 ppg grad. 1.091 psi/ft
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Artesian Well
When talking about artesian wells, we are normally talking about water wells where we have a porous sandstone witch has communication to higher laying areas creating abnormal pressure below a cap rock.
Fig 07 Under compaction
Let us consider that at a particular period in a rock formations' development it was not possible for the formation fluids to escape since an impermeable formation type placed on top prevents this from happening. Therefore the rock particles can not be compacted and consolidated sufficiently to carry the weight of the overlying rock. Since the fluid trapped in between the particles could not escape the fluid will be exposed to compressing forces.
These forces result in an increased formation fluid pressure, which is abnormal at the given depth. It can be realised that the trapped formation fluid has to carry the weight of the overlaying formation, along with the formation rock in which it is trapped. In a situation such as this the formation pressure will be greatly different from a calculated normal pressure/depth forecast.
Example:
A formation at 5000 ft depth contains formation fluid. The formation fluid has communication to the surface through porous and permeable formation rock. See fig.
08
Formation pressure at 5000 ft will be the fluid column pressure Density for formation fluid = 8.95 ppg
Pressure gradient for formation fluid = 8.95 x O.052 = 0.465 psi/ft Pf (Pressure of Formation) = 5000 x O.465 = 2325 psi
PRESSURE AT THE W ELL UNTILL BELOW THE CAP
ROCK
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Fig 08 If it is considered that this formation fluid was trapped in an earlier period in the sedimentary process and therefore could not escape the later compaction process, it is possible that the fluid may be exposed to the weight of the overlying rock mass.
Assuming formation fluid is 10% and an equivalent formation density of 21 ppg this results in the following formation pressure (Pf):
Pf = 5146.7 psi
This formation fluid is over-pressured or abnormal. Over-pressured formations are often encountered with thick salt sediments and salt domes. Salt does not have the same structure as normal rock formations. Salt is termed a "plastic" formation, which means that it is not self-supporting, it can move and deform under pressure, and (this is not necessarily a rapid process). When pressure is applied to a salt formation it behaves more as fluids rather than as solid matter. The relative strength of salt is very low compared to other rock types.
Because of the salt's qualities the weight from the overlying formation including the weight of the salt layers themselves will be transferred to the formation below the salt. The pressure in the salt and in the formation below it will often have a pressure gradient of 1 psi/ft instead of the normal pressure gradient for formation fluid, which is 0.465 psi/ft.
Abnormal pressures can also occur when an encapsulated and normal pressured formation for the particular depth at a later stage in history with movements or surface erosion is brought closer to the surface.
The particular formation in question can be found deeper or shallower in relation to its original position. If it is the case that the formation pressure cannot adjust to its new depth it will hold its original pressure.
Example:
A sandstone formation at 4000 ft depth is considered to have a normal pressure of 1860 psi. On account of geological processes the area of the sandstone becomes isolated by impermeable rock. Over time and through earth movements the formation moves to a shallower depth of 2500 ft. In this situation the sandstone will retain it's original 1860 psi pore pressure but he surrounding formation has a pore pressure of
0.052)
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Such an isolated zone is called a high-pressure zone or abnormal pressured zone.
It may as well be the case that the isolated sandstone by earth movements was brought down to 5000 ft depth. The normal pressure for 5000 ft would be 2325 psi and the isolated sandstone area with its 1860 psi would become a low-pressure or subnormal-pressured zone.
Fig 09
Abnormal pressured formations can also develop because of differences in the contained formation fluid and gas densities.
Figure 10 shows an anticline. An anticline is the geological term for an area of formations which, due to earth movements has been pushed upwards to take a shape like a dome.
In the figure the anticline consists of porous sandstone which contains gas. A layer of impermeable shale that prevents the gas from escaping caps the sandstone. The formation surrounding the anticline has a pore content of salt water and a base depth of 5000 ft. The formation pressure is considered to be normal. Formation pressure of the salt Water bearing rock at 5000 ft will therefore be:
psi 2325
= 0.465 x 5000 Pf=
4000 ft
2500 ft
5000 ft
1860 psi
1860 psi
1860 psi 1160 psi
2325 psi 1860 psi
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If the sandstone in the anticline contained salt water instead of gas, the formation pressure at the very top of the anticline would be exactly the same as the formation just above.
Example:
Pf = 3000 x 0.465 = 1395 psi
The sandstone however is containing gas, which has a pressure gradient of 0.1 psi/ft. This results in the pressure at top of the anticline to be substantially higher than the calculated 1395 psi for a salt-water formation.
The reason is that the hydrostatic pressure of gas within the anticline is much lower than the corresponding hydrostatic pressure of salt water on the outside.
Pressure from the 2000 ft high gas column will be:
Ph = 2000 x 0.1 = 200 psi
Therefore the formation pressure at the very top of the anticline below the cap rock will be:
Pf = 2325 - 200 = 2125 psi
Formation structures of this type give a real problem if the formations above and/or below will not withstand the 12.45 ppg hydrostatic pressure from the drilling fluid that is required to balance the zone at 2000 ft. It may be necessary to set several casing strings in order to isolate the pressure.
High-permeability limestone formations have small formation strength gradients, and lost circulation may be the result when the bottom well pressure exceeds formation pressure by as little as 200 psi. This value may be less than the dynamic pressure drop in the annulus or less than a safe trip margin. Such conditions can be risky if insufficient information is available.
Porous with water
Sandstone with gas
5000 ft
2325 psi 3000 ft 1395 psi
Anticline
Tight Shale 2125 psi
Fig 10
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Transition zones and under compacted shale
Wherever massive shale formations are found the risk for transition zones and high pressure is present. This is caused by thick impermeable shale restricting the disposal of formation fluid. Due to new sediments are settled on the seabed increasing weight load is exerted on the shale from the formation above. The water, gas or oil trapped within the shale cannot escape. The result is the development of abnormal pore pressures. The terminology under compacted shales is used to indicate these circumstances.
A seal of harder rock often caps the top of the abnormal pressured shale. After the cap rock is penetrated the Rate of Penetration (ROP) increases. The reason is that the shale is easier to drill since the differential pressure between drilling fluid hydrostatic pressure and the formation pressure decreases. A reduction in overbalance results in a faster drilling rate.
When the Driller maintains his drilling parameters constant (constant rotary speed, constant weight on bit and constant pump rate), the Rate of Penetration (ROP) should be constant as well, unless changes in the drilled formation takes place. The indication of changes in the formation can therefore be observed by the Driller by means of changes in Rate of Penetration. To confirm whether the well is still in balance, the Driller must stop and observe/check if the well is static. The terminology for this operation is "flow checking the well".
Fig 11
Whenever thick shales are encountered it is important to be careful and expect abnormal pressure in the formation. Shale related abnormal pressures can occur at any depth from surface to very deep and is the most common reason for abnormal formation pressure.
Because the formation fluid in under compacted shale is unable to escape, a typical trend will indicate that the cuttings density decrease with depth. The density decrease with depth can indicate that abnormal pressure is encountered.
Surcharged formations by underground blowouts
A different reason for abnormal formation pressures are the result of previous blowouts underground. Shallower sands can become charged as the result of an uncontrolled underground blow out from an adjacent well or from a bad cement job. Even the well has successfully been closed in on surface the pressure from the deeper zone can communicate to the shallower sand reservoir.
When the next well is drilled the abnormal pressure is encountered at the much shallower depth. See Fig 12
ENCLOSED SAND LENS WITH FORMATION FLUID UNCONSOLIDATED
SHALE-DENSITY DECREASES WITH DEPTH-WATER ENCLOSED SAND WITH COMMUNICATION TO SURFACE
SHALE-DENSITY INCREASES WITH DEPTH - WATER ESCAPES
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Fig 12 Fig 13
Surcharged formations by natural causes
Shallow formations may also be surcharged by natural causes. This can be the result of a fault in the formations. A fault gives a means of communication between deeper formations with high pressure and shallower formations. The higher pressure escapes into the shallower formation where an abnormal pressure will be the result. See Fig 13.
UNDERGROUND BLOWOUT
Pf
FAULT ZONE
Pf
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Section 02 PRESSURE BALANCE IN THE WELL BORE