ABNORMAL PRESSURE

PERMEABLE ZONE

NORMAL PRESSURE

SEA

FAULT

ABNORMAL PRESSURE

SEA

Abnormally high formation pressures are found worldwide in formations ranging in age from the Pleistocene age (approximately 1 million years) to the Cambrian age (500 to 600 million years). They may occur at depths as shallow as only a few hundred feet or exceeding 20,000 ft and may be present in shale/sand sequences and/or massive evaporite-carbonate sequences.

The causes of abnormally high formation pressures are related to a combination of geological, physical, geochemical and mechanical processes.

As defined, the magnitude of abnormally high formation pressures must be greater than the normal hydrostatic pressure for the location, and may be as high as the overburden pressure. Abnormally high pressure gradients will thus be between the normal hydrostatic gradient (0.433 to 0.465 psi/ft) and the overburden gradient (generally 1.0 psi/ft).

However, locally confined pore pressure gradients exceeding the overburden gradient by up to 40% are known in areas such as Pakistan, Iran, Papua New Guinea, and the CIS. These super pressures can only exist because the internal strength of the rock overlying the super pressured zone assists the overburden load in containing the pressure. The overlying rock can be considered to be in tension.

In the Himalayan foothills of Pakistan, formation pressure gradients of 1.3 psi/ft have been encountered. In Iran, gradients of 1.0 psi/ft are common and in Papua New Guinea, a gradient of 1.04 psi/ft has been reported. In one area of Russia, local formation pressure in the range of 5870 to 7350 psi at 5250 feet were reported.

This equates to a formation pressure gradient of 1.12 to 1.4 psi/ft.

In the North Sea abnormal pressures occur with widely varying magnitudes in many geological formations.

The Tertiary sediments are mainly clays and may be overpressured for much of their thickness. Pressure gradients of 0.52 psi/ft are common with locally

occurring gradients of 0.8 psi/ft being encountered. An expandible clay (gumbo) also occurs which is of volcanic origin and is still undergoing compaction. The consequent decrease in clay density would normally indicate an abnormal

pressure zone but this is not the case. However, in some areas, mud weights of the order of 0.62 psi/ft or higher are required to keep the wellbore open because of the swelling nature of these clays. This is almost equal to the low overburden

gradients in these areas.

In the Mesozoic clays of the North Sea Central Graben, overpressures of 0.9 psi/ft have been recorded. One reported case indicated a formation pressure gradient of 0.91 psi/ft in the Jurassic section. In the Jurassic of the Viking Graben, abnormal formation pressure gradients of up to 0.69 psi/ft have been recorded.

In Triassic sediments, abnormally high formation pressures have been found in gas bearing zones of the Bunter Sandstone in the southern North Sea. Also in the southern North Sea, overpressures are often found in Permian carbonates,

evaporates and sandstones sandwiched between massive Zechsteins salts.

2.3.6 SHALLOW GAS SANDS

Kicks from shallow sands (gas and water) whilst drilling in the top hole section with short casing strings can be very hazardous, as documented by many case histories. Some of the kicks from shallow sands are caused by charged formations:

poor cement jobs, casing leaks, injection operations, improper abandonments, and previous underground blowouts can produce charged formations.

2.3.7 SPECIAL SITUATIONS

a) Drill Stem Testing (DST)

The formation test is one of the most hazardous operations encountered in drilling and completing oil and gas wells. The potential for stuck tools, blowouts, lost circulations, etc., is greatly increased.

A drill stem test is performed by setting a packer above the formation to be tested, and allowing the formation to flow. Down hole chokes can be incorporated in the test string to limit surface pressures and flow rates to the capabilities of the surface equipment to handle or dispose of the produced fluid.

During the course of the test, the bore hole or casing below the packer, and at least a portion of the drill pipe or tubing, is filled with formation fluid. At the

conclusion of the test, this fluid must be removed by proper well control techniques to return the well to a safe condition. Failure to follow the correct procedures to kill the well could lead to a blowout.

b) Drilling Into an Adjacent Well

Drilling into an adjacent well is a potential problem, particularly offshore where a large number of directional wells are drilled from the same platform. If the drilling well penetrates the production string of a previously completed well, the

formation fluid from the completed well will enter the wellbore of the drilling well, causing a kick. If this occurs at a shallow depth, it is an extremely dangerous situation and could easily result in an uncontrolled blowout.

c) Excessive Drilling Rate Through a Gas Sand/Limestone

When drilling a gas bearing formation, the mud weight will be gas cut due to the gas breaking out of the pore space of the cuttings near the surface. The severity of the influx will depend on the penetration rate, porosity and permeability, and is independent of mud weight. The importance attached to gas cutting is that gas is entering the wellbore in small quantities, which calls for caution. Degassing is necessary to ensure that good mud is being pumped back into the hole to prevent the percentage of gas from increasing with each circulation, which would allow greater and greater bottom hole hydrostatic pressure reductions.

Figure 2.9 Reduction in Hydrostatic Head Due to Gas Cutting of the Mud

18 ppg mud cut 50% to 9.0 ppg

Depth Normal Head Reduced Head

18 ppg mud Head Reduction

1,000' 936 psi 866 psi 60 psi

5,000' 4,680 psi 4,598 psi 82 psi

10,000' 9,360 psi 9,265 psi 95 psi

20,000' 18,720 psi 18,615 psi 105 psi

Most of mud cutting is close to surface. Divert flow through choke manifold to prevent belching and to safely contain gas through mud gas separator. Time drill the gas cap to prevent severe gas cutting of mud.

Gas cutting alone does not indicate the well is kicking, unless it is associated with pit gain. Allowing the well to belch over the nipple could cause reduction in hydrostatic pressure to the point that the formation would start flowing, resulting in a kick.

2.4 EXTRACTS FROM API RP59

4.1 Introduction. Loss of primary well control most frequently results from:

1) failure to keep the hole full; 2) swabbing; 3) insufficient drilling fluid density;

and/or 4) lost circulation. These problems can occur during any operation conducted on a well. The goal of well control is to prevent a well kick (influx of formation fluid into the wellbore) from becoming a blowout (uncontrolled flow of formation fluid).

4.2 Conditions Necessary for a Kick. The two conditions that must be present in the wellbore for a kick to occur are 1) the pressure in the wellbore at the face of the kicking formation must be less than the formation pressure; and 2) the kicking formation must have sufficient permeability to allow flow into the wellbore. To maintain primary well control, drilling personnel should utilise all techniques at their disposal to ensure that the hydrostatic pressure in the wellbore is always greater than the formation pressure. A number of conditions which can cause or contribute to well kicks are discussed in Paras 4.3 through 4.15.

4.3 Hole Not Full of Drilling Fluid. When the fluid level in the wellbore is

allowed to drop or is maintained with a lighter density fluid, the resultant reduced hydrostatic head can allow fluid entry from the formation. The rig should have drilling fluid measuring devices to determine that proper fluid replacement or displacement occurs when pulling or running pipe. The type of fluid measuring equipment used should be influenced by the anticipated well control operations involved in drilling the well.

4.4 Tripping Out of the Hole. When pulling pipe, its displacement volume should be replaced with the proper amount of drilling fluid to maintain constant

hydrostatic pressure. Any significant reduction in hydrostatic pressure may result in loss of primary control. If the hole fails to take the proper amount of drilling fluid, hoisting operations should be suspended and an immediate safe course of action determined while observing the well. This usually requires returning to bottom and circulating the hole. The frequency of filling the hole during tripping operations is critical in maintaining primary control. The hole should be completely filled at intervals that will prevent an influx of formation fluid. Continuous filling or filling after each stand of drill pipe may be advisable. The hole should be filled after each stand of drill collars. When the hole is filled continuously, an isolated drilling fluid volume measurement facility (such as a trip tank) must be used.

4.5 Tripping In the Hole. In running pipe back in the hole, the drilling fluid volume increase at the surface should be no greater than predicted displacement.

Some holes take significant volumes of drilling fluid during trips because of seepage loss. It is necessary to keep a trip book (refer to Para. 10.3 and Table 10.1) for ready comparison to determine if an abnormal condition occurs. The gauging of fluid returns and comparison with prior trip records should provide a warning of possible loss of primary well control. The hole and fluid returns should be checked at frequent intervals.

4.6 Out of the Hole. Time with pipe out of the hole should be minimised.

Particular care should be taken when a servicing tool, such as a core barrel, with its length too great to clear the ram closure zone and/or its outside diameter too large to fit the pipe rams, to have the necessary crossover connection(s) readily available so that correct pipe movement can be effected to be able to close more than the annular blowout preventer. In case of equipment repair on drilling rigs, the pipe should be run at least back to the last easing shoe, if possible, before repairs are undertaken. In well servicing operations, when making equipment repairs, effecting routine maintenance, or shutting down overnight, the pipe should be run to a sufficient depth to ensure that the well can be controlled.

4.7 Swabbing. When pipe is pulled from a well, a reduction in bottom-hole hydrostatic pressure (swabbing) may occur. Bottom-hole pressure reduction of several hundred pounds per square inch (psi) can occur when swabbing takes place. This pressure reduction, which can be sufficient to permit the entry of formation fluid into the wellbore, is one of the major reasons for losing primary well control. This type of swabbing action should not be confused with the more obvious concept of actually pulling fluid from a well with a balled up bit or

packer, or swabbing in a producing well through tubing. When pipe is pulled from a well, swabbing can be difficult to detect. The well may take some fluid as the pipe is withdrawn but less than the complete pipe displacement. The detection of swabbing, therefore, can only be done by accurately measuring the drilling fluid added to the hole as pipe is pulled. Three prime factors in controlling swabbing are: 1) drilling fluid properties; 2) rate of pulling pipe; and 3) drill string and hole configurations.

4.8 Trip Margin. The use of a trip margin is encouraged to offset the effects of swabbing. The additional hydrostatic pressure will permit some degree of swabbing without losing primary well control.

4.9 Short Trip. After tripping and circulating “bottoms-up,” the amount of gas, salt water, or oil contamination will enable the evaluation of operating practices affecting swabbing. Adjustments in pulling speed, drilling fluid flow properties, and/or drilling fluid density may be warranted. A short trip and circulating

“bottoms-up” before pulling out of the hole can also be used to determine the system’s swabbing characteristics.

4.10 Insufficient Drilling Fluid Density. The condition where formation pressure exceeds existing hydrostatic pressure in the wellbore is referred to as under-balance and can be caused be insufficient drilling fluid density.

4.11 Lost Circulation. Lost circulation occurs in both drilling and well servicing operations and may quickly destroy the hydrostatic overbalance that constitutes primary control. The loss can result from natural or induced causes. Natural causes include fractured, vugular, cavernous, subnormally-pressured, or pressure-depleted formations. Induced loss can result from mechanical formation fracturing resulting from 1) excessive drilling fluid density, 2) excessive annular circulating

4.12 Drill Stem Testing. Drill stem tests are performed by setting a packer above the formation to be tested and allowing the formation to flow. During the course of testing, the borehole or casing below the packer and at least a portion of the drill pipe or tubing is filled with formation fluid. At the conclusion of the test, the fluid in the test string above the circulating valve must be removed by proper well control techniques, such as reversing, to return the well to a safe condition.

Depending on the length of hole below the packer, type of fluid entry, and formation pressure, the normal drilling hydrostatic overbalance can be reduced or lost. Caution should be exercised to avoid swabbing when pulling the test string because of the large diameter packers.

4.13 Drilling Into an Adjacent Well. Frequently, a large number of directional wells are drilled from the same offshore platform or onshore drilling pad. If a drilling well penetrates the production string of a previously completed well, the formation fluid from the completed well may enter the wellbore of the drilling well, causing a kick. Special care should be exercised to avoid a collision course with another well.

4.14 Excessive Drilling Rate Through a Gas Sand. Even if the drilling fluid density in the hole is sufficient to control gas zone pressure, gas from the drilled cuttings will mix with the drilling fluid. Excessive drilling rate through a shallow gas zone or coal bed can supply sufficient gas from cuttings to reduce the

hydrostatic pressure of the drilling fluid column through a progressive

combination of density reduction and drilling fluid loss from “belching” to the point that the formation will begin flowing into the wellbore.

4.15 Others. Primary control can also be lost while performing operations other than circulating, drilling, or running and pulling pipe, loss of well control can occur during coring, perforating, fishing, performing primary or remedial

cementing, running casing or liner operations, or when differential fill equipment malfunctions. All such operations require the accurate measurement and control or drilling fluid replaced or displaced in the well to maintain primary control.

Complications can occur in primary control during floating drilling operations due to distorted readings caused by motion and heave. The measurement of drilling fluid volume and flow rate is most critical in floating operations and requires pit level monitoring devices (floats) located in the centre of the pits or multi-floats with sequential integration utilised. A trip tank and pit watcher should be considered if vessel movement creates any problem in measuring drilling fluid requirements on trips.

4.16 Special Situations. The accurate prediction of pressure gradients, particularly abnormal pressure, and the prevention of an insufficient drilling fluid density situation, are highly desirable but not always attainable. In some situations of insufficient drilling fluid density, operations can be safely handled and proceed without increasing drilling fluid density, yet maintain control (underbalanced drilling). An abnormally pressured gas zone with low productivity (e.g., shale gas) is a possible example where the well will not flow appreciably but gas exists after

a trip which may require use of blowout prevention equipment and/or rotating heads. Sometimes fluid influx will occur when circulation is stopped, but will not occur during drilling operations due to the effect of annular circulating pressure.

In this instance, successful operations usually require an increase in drilling fluid density or, in some fields, the use of a lighter drilling fluid and another heavier drilling fluid to control the well on trips.