predicting formation pressures

D R I L L I N G T E C H N O L O G YR E F E R E N C E S : D R I L L I N G E N G I N E E R I N G B Y N E A L A D A M SD R I L L I N G E N G I N E E R I N G B Y H E R R I O T WAT T U N I V E R S I T Y

Predicting Formation Pressures

WELL PLANNING CONSIDERATION

Definition of Terms

The magnitude of the pressure in the pores of a formation, known as the formation pore pressure (or simply formation pressure), is an important consideration in many aspects of well planning and operations. It will influence the casing design ,mud weight, cement etc.

In most geographical areas the pore pressure gradient is approximately 0.465 psi/ft (assumes 80,000 ppm salt content) and this pressure gradient has been defined as the normal pressure gradient. Any formation pressure above or below the points defined by this gradient are called abnormal pressures. When the pore fluids are normally pressured the formation pore pressure is also said to be hydrostatic. For Normal Pressure MW = 9 ppg

The differential between the mud pressure and the pore pressure at any given depth is known as the overbalance pressure

If the mud pressure is less than the pore pressure then the differential is known as the underbalance pressure at that depth

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FORMATION FRACTURE GRADIENT - pressure at which the rocks will fracture.

The vertical pressure at any point in the earth is known as the overburden pressure or geostatic pressure. The overburden pressure at any point is a function of the mass of rock and fluid above the point of interest.

The specific gravity of the rock matrix may vary from 2.1 (sandstone) to 2.4 (limestone). Therefore, using an average of 2.3 and converting to units of psi/ft, it can be seen that the overburden pressure gradient exerted by a typical rock, with zero porosity would be :

2.3 x 0.433 psi/ft = 0.9959 psi/ft = 1 psi/ft

 ABNORMAL PRESSURES

Pore pressures which are found to lie above or below the “normal” pore pressure gradient line are called abnormal pore pressures (Figure 5 and 6). These formation pressures may be either Subnormal (i.e. less than 0.465 psi/ft) or Overpressured (i.e.greater than 0.465 psi/ft). The mechanisms which generate these abnormal pore pressures can be quite complex and vary from region to region. However, the most common mechanism for generating overpressures is called Undercompaction

mechanisms which cause over pressures to develop

1. Incomplete sediment compaction or undercompaction is the most common mechanism causing overpressures.

2. Faulting-Faults may redistribute sediments, and place permeable zones opposite impermeable zones, thus creating barriers to fluid movement. This may prevent water being expelled from a shale, which will cause high porosity and Phase Changes during Compaction

3. Massive Rock Salt DepositionDeposition of salt can occur over wide areas. Since salt is impermeable to fluids the underlying formations become overpressured. Abnormal pressures are frequently found in zones directly below a salt layer.

MECHANISM

1. Salt Diaperism2. This is the upwards movement of a low density salt dome due to buoyancy

which disturbs the normal layering of sediments and produces pressure anomalies. The salt may also act as an impermeable seal to lateral dewatering of clays.

3. Tectonic Compression4. The lateral compression of sediments may result either in uplifting

weathered sediments or fracturing/faulting of stronger sediments. Thus formations normally compacted at depth can be raised to a higher level. If the original pressure is maintained the uplifted formation is now overpressured.

5. Repressuring from Deeper Levels6. This is caused by the migration of fluid from a high to a low presssure

zone at shallower depth. This may be due to faulting or from a poor casing/cement job. The unexpectedly high pressure could cause a kick, since no lithology change would be apparent. High pressures can occur in shallow sands if they are charged by gas from lower formations.

Density Differences. Fluid density differences between zones with connecting

permeability can cause abnormal pressures.

Example of Overpressured/Abnormal Formations

These are formations whose pore pressure is greater than that corresponding to the normal gradient of 0.465 psi/ft.

1. Gulf Coast 0.8 - 0.9 psi/ft2. Iran 0.71 - 0.98 “3. North Sea 0.5 - 0.9 “4. Carpathian Basin 0.8 - 1.1 “

Simple Calculation of Formation with abnormal Pressure

DRILLING PROBLEMS ASSOCIATED WITH ABNORMAL FORMATION

PRESSURES

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

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

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

Reduced penetration rates (due to chip hold down effect) Breakdown of formation (exceeding the fracture gradient)

and Subsequent lost circulation (flow of mud into formation) Excessive differential pressure causing stuck pipe

Pressure Prediction Methods

Several methods of pressure prediction are available to the engineer. These methods can be grouped logically as follows:I. areal analysis from seismic data2. offset well correlation log analysis drilling parameter evaluation production or test data3. real-time evaluation qualitative quantitativeThe real-time analysis involves monitoring drilling and logging parameters while the prospect well is drilled (MWD/LWD) wire line etc..

DRILLING PARAMETER EVALUATION

Calculating the Fracture Pressure of a Formation

It is however necessary, in order to ensure a safe operation and to optimise the design of the well, to have an estimate of the fracture pressure of the formations to be drilled before the drilling operation has been commenced. In practice the fracture pressure of the formations are estimated from leakoff tests on nearby (offset) wells.

Field Determination of Fracture Gradients

It is common practice to pressure-test each new casing seat in field applications to determine the exact minimum fracture gradient. The primary reason for this practice is due to the inability of any theoretical procedure to account for all possible formation characteristics. For example, several authors have noted wells that exhibited lower-than-expected fracture gradients due to abnormally low bulk densities in the rock.

The most common procedure used for the field determination of fracture gradients is the leakoff test (often called the pressure integrity test). In the test,the blowout preventers are closed and then pressure is applied incrementally to the shutin system until the formation initially accepts fluid. The results of the test would be similar to those shown in Fig. 4-10. Example 4.3 illustrates the procedure

Casing was set at 10,000 ft in a well. The operator performs a leak off test to determine the fracture gradient at 10,000 ft. If the mud weight in the well was 11.2 Ib/gal, what is the fracture gradient at the casing seat?