The Maximum Allowable Annular Surface Pressure – MAASP – when drilling ahead is the maximum closed in (not circulating) pressure that can be applied to the annulus (drillpipe x BOP) at surface before the formation just below the casing shoe will start to fracture (leak off). The MAASP can be determined from the following equation:

MAASP = Maximum Allowable pressure at the formation just below the shoe minus the Hydrostatic Pressure of mud at the formation just below the shoe.

Institute of Petroleum Engineering, Heriot-Watt University

It is clear from all of the preceding discussion that the pressure at the bottom of the borehole must be accurately determined if the leak off or fracture pressure of the formation is not to be exceeded. When the drilling fluid is circulating through the drillstring, the borehole pressure at the bottom of the annulus will be greater than the hydrostatic pressure of the mud. The extra pressure is due to the frictional pressure required to pump the fluid up the annulus. This frictional pressure must be added to the pressure due to the hydrostatic pressure from the colom of mud to get a true representation of the pressure acting against the formation a the bottom of the well. An equivalent circulating density (ECD) can then be calculated from the sum of the hydrostatic and frictional pressure divided by the true vertical depth of the well. The ECD for a system can be calculated from:

cal 2

where ,
ECD= effective circulating density (ppg)
MW= mud weight (ppg)
Pd = annulus frictional pressure drop at a given circulation rate (psi)
D = depth (ft)

The ECD of the fluid should be continuously monitored to ensure that the pressure at the formation below the shoe, due to the ECD of the fluid and system, does not exceed the leak off test pressure.

Institute of Petroleum Engineering, Heriot-Watt University

In a Leak-Off test the formation below the casing shoe is considered to have started to fracture at point A on Figure 24. The surface pressure at ponit A is known as the leak off pressure and can be used to determine the maximum allowable pressure on the formation below the shoe. The maximum allowable pressure at the shoe can subsequently be used to calculate:

The maximum mudweight which can be used in the subsequent openhole section
The Maximum Allowable Annular Surface Pressure (MAASP)

The maximum allowable pressure on the formation just below the casing shoe is generally expressed as an equivalent mud gradient (EMG) so that it can be compared with the mud weight to be used in the subsequent hole section.

Given the pressure at surface when leak off occurs (point A in Figure 24) just below the casing shoe, the maximum mudweight that can be used at that depth, and below, can be calculated from :

cal 1

Usually a safety factor of 0.5 ppg (0.026 psi/ft) is subtracted from the allowable mudweight.

It should be noted that the leak-off test is usually done just after drilling out of the casing shoe, but when drilling the next hole section other, weaker formations may be encountered.

Institute of Petroleum Engineering, Heriot-Watt University

The pressure at which formations will fracture when exposed to borehole pressure is determined by conducting one of the following tests:

1. Leak-off test
2. Limit Test
3. Formation Breakdown Test

The basic principle of these tests is to conduct a pressure test of the entire system in the wellbore (See Figure 21 ) and to determine the strength of the weakest part of this system on the assumption that this formation will be the weakest formation in the subsequent open hole. The wellbore is comprised of (from bottom to top): the exposed formations in the open hole section of the well (generally only 5-10ft of formation is exposed when these tests are conducted); the casing (and connections);

formation integrity test

the wellhead; and the BOP stack. The procedure used to conduct these tests is basically the same in all cases. The test is conducted immediately after a casing has been set and cemented. The only difference between the tests is the point at which the test is stopped. The procedure is as follows:

1.  Run and cement the casing string
2.  Run in the drillstring and drillbit for the next hole section and drill out of the casing shoe
3.  Drill 5 – 10 ft of new formation below the casing shoe
4.  Pull the drillbit back into the casing shoe (to avoid the possibility of becoming stuck in the openhole)
5.   Close the BOPs (generally the pipe ram) at surface
6.   Apply pressure to the well by pumping a small amount of mud (generally 1/2 bbl) into the well at surface. Stop pumping and record the pressure in the well. Pump a second, equal amount of mud into the well and record the pressure at surface. Continue this operation, stopping after each increment in volume and recording the corresponding pressure at surface. Plot the volume of mud pumped and the corresponding pressure at each increment in volume. (Figure 22).

(Note: the graph shown in Figure 21 represents the pressure all along the wellbore at each increment. This shows that the pressure at the formation at leak off is the sum of the pressure at surface plus the hydrostatic pressure of the mud).

7.   When the test is complete, bleed off the pressure at surface, open the BOP rams and drill ahead.

It is assumed in these tests that the weakest part of the wellbore is the formations which are exposed just below the casing shoe. It can be seen in Figure 21, that when these tests are conducted, the pressure at surface, and throughout the wellbore, initially increases linearly with respect to pressure. At some pressure the exposed formations start to fracture and the pressure no longer increases linearly for each increment in the volume of mud pumped into the well (see point A in Figure 22). If the test is conducted until the formations fracture completely (see point B in Figure 22) the pressure at surface will often dop dramatically, in a similar manner to that shown in Figure 22.

ductile rock

The precise relationship between pressure and volume in these tests will depend on the type of rock that is exposed below the shoe. If the rock is ductile the behaviour will be as shown in Figure 22 and if it is brittle it will behave as shown in Figure 23.

brittle rock

The “Leak-off test” is used to determine the pressure at which the rock in the open hole section of the well just starts to break down (or “leak off”). In this type of test the operation is terminated when the pressure no longer continues to increase linearly as the mud is pumped into the well (See Figure 24). In practice the pressure and volume pumped is plotted in real time, as the fluid is pumped into the well.

leakoff test

When it is seen that the pressure no longer increases linearly with an increase in volume pumped (Point C) it is assumed that the formation is starting to breakdown.
When this happens a second, smaller amount of mud (generally 1/4 bbl) is pumped into the well just to check that the deviation from the line is not simply an error (Point D). If it is confirmed that the formation has started to “leak off” then the test is stopped and the calculations below are carried out.

The “Limit Test” is used to determine whether the rock in the open hole section of the well will withstand a specific, predetermined pressure. This pressure represents the maximum pressure that the formation will be exposed to whilst drilling the next wellbore section. The pressure to volume relationship during this test is shown in Figure 25. This test is effectively a limited version of the leak-off test.

limit test

The “Formation Breakdown Test” is used to determine the pressure at which the rock in the open hole section of the well completely breaks down. If fluid is continued to be pumped into the well after leak off and breakdown occurs the pressure in the wellbore will behave as shown in Figure 26.

Institute of Petroleum Engineering, Heriot-Watt University

The stress within a rock can be resolved into three principal stresses (Figure 20). A formation will fracture when the pressure in the borehole exceeds the least of the stresses within the rock structure. Normally, these fractures will propagate in a direction perpendicular to the least principal stress (Figure 20). The direction of the least principal stress in any particular region can be predicted by investigating the fault activity in the area (Figure 21).

stresses

To initiate a fracture in the wall of the borehole, the pressure in the borehole must be greater than the least principal stress in the formation. To propagate the fracture the pressure must be maintained at a level greater than the least principal stress.

formation integrity test

The theory behind using drilling parameters to detect overpressured zones is based on the fact that:

1. Compaction of formations increases with depth. ROP will therefore, all other things being constant, decrease with depth.
2. In the transition zone the rock will be more porous (less compacted) than that in a normally compacted formation and this will result in an increase in ROP. Also, as drilling proceeds, the differential pressure between the mud hydrostatic and formation pore pressure in the transition zone will reduce, resulting in a much greater ROP.

The use of the ROP to detect transition and therefore overpressured zones is a simple concept, but difficult to apply in practice. This is due to the fact that many factors affect the ROP, apart from formation pressure (e.g. rotary speed and WOB).  Since these other effects cannot be held constant, they must be considered so that a direct relationship between ROP and formation pressure can be established. This is achieved by applying empirical equations to produce a “normalised” ROP, which can then be used as a detection tool.

Detection techniques are used whilst drilling the well. They are basically used to detect an increase in pressure in the transition zone. They are based on three forms of data:

1. Drilling parameters – observing drilling parameters (e.g.ROP) and applying empirical equations to produce a term which is dependent on pore pressure.
2. Drilling mud – monitoring the effect of an overpressured zone on the mud (e.g. in temperature, influx of oil or gas).
3. Drilled cuttings – examining cuttings, trying to identify cuttings from the sealing zone.

The predictive techniques are based on measurements that can be made at surface, such a geophysical measurements, or by analysing data from wells that have been drilled in nearby locations (offset wells). Geophysical measurements are generally used to identify geological conditions which might indicate the potential for overpressures such as salt domes which may have associated overpressured zones. Seismic data has been used successfully to identify transition zones and fluid content such as the presence of gas. Offset well histories may contain information on mud weights used, problems with stuck pipe, lost circulation or kicks. Any wireline logs or mudlogging information is also valuable when attempting to predict overpressures.

It is clear from the descriptions of the ways in which overpressures are generated above that the pore pressure profile in a region where overpressures exist will look something like the P-Z diagram shown in Figure 13. It can be seen that the pore pressures in the shallower formations are “normal”. That is that they correspond to a hydrostatic fluid gradient. There is then an increase in pressure with depth until the “overpressured” formation is entered. The zone between the normally pressured zone and the overpressured zone is known as the transition zone.

The pressures in both the transition and overpressured zone is quite clearly above the hydrostatic pressure gradient line. The transition zone is therefore the seal or caprock on the overpressured formation. It is important to note that the transition zone shown in Figure 13 is representative of a thick shale sequence. This shale will have some low level of porosity and the fluids in the pore space can therefore be overpressured. However, the permeability of the shale is so low that the fluid in the shale and in the overpressured zone below the shale cannot flow through the shale and is therefore effectively trapped. Hence the caprock of a reservoir is not necessarily a totally impermeable formation but is generally simply a very low permeability formation.

If the seal is a thick shale, the increase in pressure will be gradual and there are techniques for detecting the increasing pore pressure. However, if the seal is a hard, crystalline rock (with no permeability at all) the transition will be abrupt and it will not be possible to detect the increase in pore pressure across the seal.

When drilling in a region which is known to have overpressured zones the drilling crew will therefore be monitoring various drilling parameters, the mud, and the drilled cuttings in an attempt to detect this increase in pressure in the transition zone. It is the transition zone which provides the opportunity for the drilling crew to realise that they are entering an overpressured zone. The key to understanding this operation is to understand that although the pressure in the transition zone may be quite high, the fluid in the pore space cannot flow into the wellbore. When however the drillbit enters the high permeability, overpressured zone below the transition zone the fluids will flow into the wellbore. In some areas operating companies have adopted the policy of deliberately reducing the overbalance so as to detect the transition zone more easily – even if this means taking a kick.

It should be noted that the overpressures in a transition zone cannot result in an influx of fluid into the well since the seal has, by definition, an extremely low permeability.The overpressures must therefore be detected in some other way.

Institute of Petroleum Engineering, Heriot-Watt University

When drilling through a formation sufficient hydrostatic mud pressure must be
maintained to

1. Prevent the borehole collapsing and
2. Prevent the influx of formation fluids.

To meet these 2 requirements the mud pressure is kept slightly higher than formation pressure. This is known as overbalance. If, however, the overbalance is too great this may lead to:

1. Reduced penetration rates (due to chip hold down effect)
2. Breakdown of formation (exceeding the fracture gradient) and subsequent lost circulation (flow of mud into formation)
3. Excessive differential pressure causing stuck pipe.

The formation pressure will also influence the design of casing strings. If there is a zone of high pressure above a low pressure zone the same mud weight cannot be used to drill through both formations otherwise the lower zone may be fractured.

The upper zone must be “cased off”, allowing the mud weight to be reduced for drilling the lower zone. A common problem is where the surface casing is set too high, so that when an overpressured zone is encountered and an influx is experienced, the influx cannot be circulated out with heavier mud without breaking down the upper zone. Each casing string should be set to the maximum depth allowed by the fracture gradient of the exposed formations. If this is not done an extra string of protective casing may be required. This will not only prove expensive, but will also reduce the wellbore diameter. This may have implications when the well is to be completed since the production tubing size may have to be restricted.

Having considered some of these problems it should be clear that any abnormally pressured zone must be identified and the drilling programme designed to accommodate it.

Institute of Petroleum Engineering, Heriot-Watt University