Well Control Eni Manual

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WELL CONTROL

Training course based upon the contents of the

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I N D E X

1. PRESSURES AND GENERAL PRINCIPLES 1

1.1 Hydrostatic pressure 3

1.2 Static pressure 7

1.3 Pressure losses 8

1.4 Bottom hole pressure 20

1.5 Formation pressure 23

1.6 Fracture pressure 24

1.7 Pressure loss (slow circulating pressure) 28

1.8 Shut-in pressures 30

1.9 Circulating pressure 31

1.10 Gas law 32

1.11 Gas migration in a closed-in well, without expansion 33 1.12 Gas migration in an open well with uncontrolled expansion 34 1.13 Gas migration in a closed-in well with a controlled expansion 35

1.14 Representation with a tube "U" 36

2. CAUSES OF KICK 39

2.1 Abnormal pressure 42

2.2 Failing to fill the hole properly while tripping - out 43

2.3 Swabbing 45

2.4 Loss of circulation 48

2.5 Decrease of mud density 49

2.6 Gas-cut mud 50

2.7 Particular situations 52

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3.1 Flow rate increase 58

3.2 Hole keeps flowing with pumps stopped 58

3.3 Pit volume increase 59

3.4 Increase in penetration rate (drilling break) 60

3.5 Lesser decrease of the mud level during the tripping- out operations 61 3.6 Decrease of circulating pressure and increase of pump strokes 62

3.7 Gas-cut mud 63

3.8 Others indicators 64

3.9 Synthesis 65

4. SHUT-IN PROCEDURES 67

4.1 Well shut - in procedures: soft shut-in and hard shut-in 69

4.2 Shut-in during drilling 71

4.3 Shut-in during tripping: with drill pipes 72

4.4 Shut-in during tripping: with drill collars 73

4.5 Warnings 74

4.6 Crew drill 75

4.7 Stabilization of the SIDPP and SICP pressure values 76

5. WELL CONTROL METHODS 81

5.1 Driller's method 84

5.2 Pressure at the shoe 90

5.3 Wait and weight method 93

5.4 Considerations on driller's method and wait and weight method 98

5.5 Volumetric method 100

5.6 Lubrication 103

5.7 Stripping or snubbing 105

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PRESSURE AND

GENERAL PRINCIPLES

___________________________________________________________________________________ Eni Corporate University

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_______________________________________________________________________________________ Eni Corporate University 2

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PRESSURE

Definition If a force F acts perpendicularly on a surface A, the intensity of the force with respect to the surface area is defined "Pressure" :

F P =

A

Expressing F in kg and A in cm2,_{, the pressure is expressed in kg/cm}_2.

1.1 HYDROSTATIC PRESSURE ( P_H)

Definition The hydrostatic pressure of a fluid at any given depth is the pressure represented by the weight of the fluid column pressing on a given surface area. A body immersed in a fluid at a given depth H is not only subject to the atmospheric pressure (acting on the fluid surface) but also to the pressure due to the mass of the liquid over it. This latter pressure is defined hydrostatic pressure P_H

Defining: H = fluid column depth (vertical depth) D = fluid density (mud) or specific weight

the hydrostatic pressure P_H is defined by the following expression:

P = D H 10

H ×

We consider 10 as a conversion factor necessary for the correct dimensioning of the values, because of the different measuring units. In the metric system, density is expressed in kg/l, while pressure is expressed in kg/cm2.

Thus, if we consider that at a density D=1 we have that 1 litre = 1 dm3 = 1000 cm3 and since Pressure = Height x Density , we obtain :

Pressure = m x [kg] [l] = 100 cm x [ kg] [1000 cm ]3 = 1 10 x [ kg] [cm ]2

Which means that for a correct dimensioning , pressure must be divided by a 10 factor.

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The main characteristics of hydrostatic pressure are:

• it is in direct proportion to the vertical depth

• it is in direct proportion to the fluid density

• it does not depend on the shape and the volume of the fluid container

• as it is true for all pressures, it exerts an equal force in all directions

Unit of measurement

The unit used for measuring pressure P_H depends on the system of measurement selected. In the Metric System (or Italian Technical System) it is expressed in kg/cm2.

The table below summarises the units of measurement and the conversion factors of the most commonly used systems of measurement.

SYSTEMS OF MEASUREMENT Value Metric System International practical system pure English system Density D kg/l kg/l kg/m3 _ppg Depth H m m m ft

Pressure P_H kg/cm2 bar kPa psi

Conversion Factor

10 0,0981 0,00981 0,052

Formula for the calculation of P_H D x H 10 D x H x 0,0981 D x H x 0,00981 D x H x 0,052 _______________________________________________________________________________________ Eni Corporate University 4

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As shown in the table below, for conversion from one system to another, pressure must be multiplied by conversion factors :

CONVERSIONS FROM ONE SYSTEM TO ANOTHER

From the metric system to the international practical system: kg/cm2 _{x 0.981 = bar}

From the metric system to the international pure system: kg/cm2 x 98,1 = kPa

From the metric system to the English system: kg/cm2 : 0.0703 = psi

Example:

100 kg/cm² x 0.981 = 98.1 bar 100 kg/cm² x 98.1 = 9810 kPa 100 kg/cm² : 0.0703 = 1422 psi Example of calculation of P_H

If a D = 1,5 kg/l density mud is used in a well which has a vertical depth H = 4.000 m, the hydrostatic pressure is:

P_H= D x H 10 =

1, 5 x 4. 000

10 = 600 kg/cm 2

The hydrostatic pressure can be described by the following diagram:

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Hydrostatic pressure gradient (G)

Definition The hydrostatic pressure gradient is the relationship between pressure and vertical depth.

In other words, the gradient represents the linear increase of pressure referred to the increase of linear depth. If we could hypothetically enter inside a fluid container, knowing the gradient, we would know the increase in hydrostatic pressure for each meter of descent towards the bottom.

G = P

H =

D 10

H

The gradient is expressed in kg/cm2_{per metre:} Kg

m

cm2 ⋅

In practical work, the unit of the gradient is not 1 metre, but 10 metres. Thus:

G = P

H x 10 =

D x H

10 x H x 10 = D

Therefore, if referred to 10 metres, the hydrostatic pressure gradient inside the well is numerically equivalent to the density of the mud.

The hydrostatic pressure can be defined by the pressure gradient as follows:

P = H GH ⋅

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1.2 STATIC PRESSURE (PS)

Definition The static pressure is the pressure measured at the surface of a closed well without circulation.

Characteristics:

• it exists only when the well is closed

• it is produced by pressures trapped within the well.

• it increases the pressure at the bottom of the well

• in kick conditions it exists in two different forms: . SIDPP: Shut In Drill Pipe Pressure . SICP : Shut In Casing Pressure

• during drilling operations it is utilised for: . BOP test

. Leak Off test

Graphic representation

Referring to the example given for the hydrostatic pressure, if we hypothetically close the well assuming a P_S=100 kg/cm2 , the graphic description of the pressure within the well is as follows:

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1.3 PRESSURE LOSSES

Definition Pressure losses result in a drop of pressure due to the friction forces opposing to the fluid flow.

Pressure losses in a pipe are represented by the following general formula: Fluid density x Pipe length x (Fluid flow rate)x ∆P =

(Pipe inside diameter) 5

In the formula the value of x (the exponent) depends on the type of fluid flow (layer flow x = 1, or turbulent flow, x= 2). In the case of mud flow circuit we assume x = 1.86

By this general formula it is possible to point out the main factors affecting pressure losses. In fact, pressure losses:

• vary linearly with the fluid density (they increase in direct proportion to density)

• vary linearly with the pipe length (they increase in direct proportion to the pipe length)

• vary substantially with the circulation velocity (they increase sharply when circulation velocity increases)

• decrease with increases of pipe diameters

Dependence of pressure losses on the pipe flow rate and on the fluid density

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The flow rate (Q) of a pipe having a section A can be expressed in relation to fluid velocity V as:

Q = V x A

Therefore,

∆

P increases sharply with increases in flow rate.

If a fluid is pumped into the same circuit with different flow rates, the following relation between pressure losses and flow rate exists:

∆P1 Q12 = ∆P2 Q22

In drilling the flow rate is termed "circulation flow rate" and it is determined by the number of pump strokes (SPM). Utilizing the pump strokes, the given relation becomes :

∆P1 SPM12 =

∆P2 SPM22

If fluids with different densities are pumped in a circuit with the same flow rate, the pressure losses are in direct proportion to the densities.

∆P1 D1 = ∆P2 D2 Pressure losses in the hydraulic circuit of the well.

Pressure losses in the hydraulic circuit of the well are distributed:

• in surface lines

• inside the drill pipes (DPs)

• inside the drill collars (DCs)

• through the bit nozzles

• in the annulus hole-drill collars

• in the annulus hole-drill pipes

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a) pressure losses in the surface lines

The pressure losses through the surface lines determine the pressure necessary for circulating the mud from the pump to the top of the pipes.

The pressure losses through the surface lines depend on the following factors:

• flow rate

• mud density

• type of surface piping system

The value of such DP is determined by means of the chart provided at the end of this chapter (table 1).

Knowing the flow rate, the table gives DP values with a mud density = 1. By multiplying this value by the mud density inside the well we obtain the value of pressure losses in the surface lines.

∆P = (table value) x mud density

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b) pressure losses inside the Drill Pipes

The pressure losses inside the drill pipes determine the pressure necessary for circulating the mud throughout the pipes.

They depend on:

• flow rate

• mud density

• internal diameter and type of drill pipes

The value of these pressure losses is determined by means of Table 2, which, in function of the flow rate and of the type of pipes, gives the pressure losses every 100 metres. Once this value has been determined, pressure losses are given by the following formula:

∆ P = table value

100 x pipe length x mud density

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c) pressure losses inside the Drill Collars

They determine the pressure necessary for circulating the mud throughout the drill collars.

They depend on:

• flow rate

• mud density

• internal diameter and type of drill collar and heavy wate

The value is determined by means of Table 3 which, in function of the flow rate and of the type of drill collars, gives the pressure losses every 100 metres. Once this value has been determined, pressure losses are given by the following formula:

100 x (pipe length+havy wate length) x mud density

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d) pressure losses through the bit nozzles

They determine the pressure necessary for circulating the mud through the bit.

They depend on:

• flow rate

• mud density

• surface area of the bit nozzles

The value of these pressure losses is determined by means of Table 8. Depending on the bit type and on the surface area of the nozzles, from table 8 we obtain a value which, multiplied by the mud density, gives the pressure losses:

∆P = table value x mud density

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e) pressure losses in the annulus between hole and drill collars

The pressure losses inside the annulus between hole and drill collars determine the pressure necessary for pumping up the mud from the bit to the top of the drill collars.

They depend on:

• flow rate

• mud density

• hole diameter

• external diameter of drill collars

By means of table 4, which gives pressure losses every 100 metres with mud density = 1 , in function of the flow rate, it is possible to calculate these pressure losses by the following formula:

100 x drill collars length x mud density

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f) pressure losses inside the annulus between hole and drill pipes

They determine the pressure necessary for pumping up the mud through the annulus for the entire length of drill pipes.

They depend on:

• flow rate

• mud density

• hole diameter

• external diameter of drill pipes

The value of these pressure losses is determined by means of Table 7 which, known the flow rate, gives the pressure losses every 100 metres with a mud density = 1. The following formula shall then be applied:

∆P = (table value)

100

drill pipes length mud density

x x

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Pressure losses throughout the mud circulation system (example)

The above example points out the pressure losses throughout the mud circulation system. As it can be observed, pressure losses mainly take place through the bit.

Only minor pressure losses take place in the annulus. However, these losses are to be considered highly important, since they contribute to the total pressure at the bottom hole, as they add to the hydrostatic pressure acting inside the well.

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Example:

Clculation of pressure losses

Hole ∅ = 12 ¼ " Depth 3000 mt DPs 5" E 2850 mt DCs 8" x 12 13/16 " 150 mt RB 3 x ½" Mud density (D) 1,4 kg/lt Flow rate (Q) 2300 lt/min

SURFACE PIPING SYSTEM (Tab. n° 1)

Q = 2300 ---> ∆P = 3,6 Kg/cm2 (D = 1,00) ∆P = 3,6 x 1,4 = 5 Kg/cm2 (D = 1,4) INSIDE DP S 64 Kg / cm2 (Tab. n 2)° → → × × → Q = 2300 P = 1,6 Kg / cm for 100 mt P (DPs length) 2850 100 1,6 = 45,6 Kg / cm (D = 1,00) P = 45,6 1,4 = 63,84 (D = 1,4) 2 2 ∆ ∆ ∆ INSIDE DC 24 Kg / cm S 2 (Tab. n 3)° → × = × → Q = 2300 P for 100 mt = 11,5 Kg / cm P for 150 mt = 150 100 11,5 = 17,25 Kg / cm (D = 1,00) P (D 1,4) = 17,25 1,4 = 24,15 2 2 ∆ ∆ ∆ ANNULUS DC - HOLE Kg / cm2 0,4 (Tab. n 5)° → × = × → Q = 2300 P for 100 mt = 0,19 Kg / cm P for 150 mt = 150 100 0,19 = 0,28 Kg / cm (D = 1,00) P (D 1,4) = 0,28 1,4 = 0,39 2 2 ∆ ∆ ∆ ___________________________________________________________________________________ Eni Corporate University

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ANNULUS DP - HOLE 2,2 kg / cm2 (Tab. n 7)° → × = × →

Q = 2300

P for 100 mt = 0,056 kg / cm P for 2850 mt = 2850 100 0,056 = 1,59 kg / cm (D = 1,00) P (D 1,4) = 1,59 1,4 = 2,23 2 2 ∆ ∆ ∆ BIT (Tab. n° 8) Q = 2300 ---> area 3 nozzle F 1/2" = 3 x 1,26 = 3,8 cm2 ∆P (Area 3,8 cm2) = 60 Kg/cm2 (Mud D = 1,00) ∆P (Mud D = 1,4) = 60 x 1,4 = 84 Kg/cm2

PRESSURE LOSSES TOTAL = 180 Kg/cm2

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Pressure losses in the annulus ( ∆_{Pan )}

Among the different types of pressure losses, those produced in the annulus are of great importance, since they modify the bottom hole pressure.

Their value is in function of the characteristics of the mud, of the circulation flow rate adopted and of the hole geometry.

At each depth, during circulation, a dynamic pressure (Back Pressure) is exerted. The value of such pressure is given by the sum of hydrostatic pressure and pressure losses in the annulus.

P

BH

= P +

H

∆

P

an Exemple 1: Hole ∅ = 12" ¼ Depth 3000 mt DPs 5" E 2850 mt ∆Pan = 2,77 kg/cm2 DCs 8" x 12 13/16 " 200 mt Mud density (D) 1,5 kg/lt Flow rate (Q) 2200 lt/min

Exemple 2: Hole ∅ = 8" ¼

Depth 3000 mt

DPs 5" E 2800 mt ∆Pan = 18,75 kg/cm2 DCs 6" ½ x 12 13/16 200 mt

Mud density (D) 1,5 kg/lt Flow rate (Q) 2200 lt/min

The above examples show how pressure losses increase substantially in direct proportion to the decrease in the hole diameter.

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1.4 BOTTOM HOLE PRESSURE ( PB )

Definition The bottom hole pressure (PB) is the total pressure acting at the bottom of the well.

Its value depends on the different combinations of work procedures:

1. Open well and pump turned off 2. Open well with circulation 3. Closed well and pump turned off

4. Closed well with circulation through the choke

1.Open well and pump turned off:

The bottom hole pressure is equivalent to the hydrostatic pressure (PH): PB = PH

2. Open well with circulation:

the bottom hole pressure is given by adding the hydrostatic pressure (PH) to the pressure losses in the annulus (DPan):

PB = PH + ∆_Pan

3. Closed well and pumped turned off:

the bottom hole pressure is given by adding the hydrostatic pressure (PH) to the pressure losses in the annulus (PS):

PB = PH + PS

4. Closed well with circulation through the choke:

the bottom hole pressure is given by adding the hydrostatic pressure (PH) to the static pressure (PS) and to the pressure losses in the annulus (Pan):

PB = PH + PS + ∆_Pan

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The following scheme summarises what has been said above and gives a graphic representation of the different components of the bottom hole pressure:

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Equivalent circulating density ECD

Definition ECD represents the mud density that can determine, with no circulation taking place, a hydrostatic pressure at the bottom of the well which is equal to the pressure when circulation takes place.

When drilling is done in permeable formations and in balance, at turning off the pump the pressure losses in the annulus cease and this could result in formation fluids that have been formed entering in the well. Knowing the ECD it is possible to determine the increase in mud density which is necessary to avoid a kick.

The ECD value can be obtained by adding to the density of the mud inside the well the density necessary to compensate the pressure losses ∆Pan. Hence:

ECD = D + (∆Pan) x 10/ H

Safety margin (S)

The safety margin (S) is a pressure that can be added to that at the top of the well so as to work with a bottom hole pressure which is slightly greater than the formation pressure

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1.5 FORMATION PRESSURE ( PF )

Definition The formation pressure (or pore pressure) is the pressure exerted by the fluids contained in the formation.

It depends on the following formation characteristics: - porosity

- permeability

The term porosity expresses the following ratio:

volume of empty spaces rock volume

x 100

while permeability is the property which allows the fluids to pass. The greater the extent to which the pores are connected, the greater the permeability of the rock. The unit of measurement used for permeability is the Darcy (we generally use the submultiple, the milliDarcy).

The formation pressure acts on the bottom and walls of the well. To avoid seepage of formation fluids (kick) the hydrostatic pressure of the well must be equal to the formation pressure:

HYDROSTATIC EQUILIBRIUM PH = PF

Maintaining hydrostatic equilibrium at the bottom of the well is the most important objective of the primary control.

In practical work, a pressure (TM, Trip Margin) able to compensate the pressure variations due to raising and lowering trips is added to the hydrostatic equilibrium.

In such conditions the hydrostatic pressure is:

PH = PF + TM

Formation pressure: normal and abnormal

Definition The formation pressure (PF) is considered normal when it is equivalent to the pressure of a column of saline water with a density D* between 1.03 and 1.07 kg/l; it is considered abnormal if it is otherwise.

Defining the pressure gradient "G", we obtain:

if G < 1,03 kg/cm2/10 m we have abnormally low pressure with risk of fractures if 1,03 <= G <= 1,07 kg/cm2/10 m we have normal pressure

if G > 1,07 kg/cm2/10 m we have abnormally high pressure with risk of kick

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1.6 FRACTURE PRESSURE ( PFR₎

Definition The fracture pressure (PFR) is the pressure that produces a partial loss of mud without actually causing the breaking of the formation.

Keeping the well at a pressure higher than fracture pressure will cause a loss of circulation. Leak-off test

The fracture pressure is usually determined by means of an experimental procedure, the "Leak-off test". In practice, the Leak-"Leak-off test determines the MAASP (maximum allowable annular surface pressure) without causing any formation fractures. Once this value has been determined, and remembering that fractures take place in the weakest point (usually under the shoe), the fracture pressure can be calculated by adding to the hydrostatic pressure at the shoe (PHs) the pressure value obtained by means of the test.

PFR = MAASP + PHs

Leak-off test procedure

1. Drill a short open hole section ( 3 - 5 metres) 2. Circulate and condition mud

3. Pull the bit to the casing shoe 4. Close the BOP

5. Pump mud

6. Record the pressure values and plot them on a graph. (time and pressure). 7. Join the points (a straight line is obtained)

- The test ends when the points diverge considerably from the straight line. - The last point on the straight line will be the value of MAASP.

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The leak-off test procedure is important during exploration of wells and when the fracture gradient is unknown.

The test can be carried out following two different procedures:

- pumping volumes at those time intervals necessary for balancing the pressures - at a 40-80 liters/min. constant rate, with cementing unit

MAASP

(Maximum Allowable Annular Surface Pressure)

Definition The MAASP (Maximum Allowable Annular Surface Pressure) is the maximum pressure at the surface annulus just before the formation fractures at its weakest point (usually below the last casing shoe). The MAASP is the maximum pressure recorded during the leak-off test:

MAASP = PFR - PHs The MAASP value is very important for the well control.

The MAASP depends on the hydrostatic pressure at the shoe and therefore it varies in relation with:

• mud density and, in case of kick, in relation with

• the height of the influx above the casing shoe

By changing the mud density the hydrostatic pressure at the casing shoe will change, then, since the fracture pressure is constant, the MAASP will vary. In practice we have:

Increase in mud density ======> MAASP decrease Decrease in mud density ======> MAASP increase

The MAASP must be recalculated when the mud density changes (without repeating the leak-off test, but referring to the formula of the MAASP).

Since the hydrostatic pressure at the casing shoe PHs decreases during the migration of gas, the MAASP increases in a way that depends on the type of fluid (liquid or gas), as it is shown in the following graph:

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The MAASP value must not be exceeded as long as the influx remains in the open hole.

As soon as the influx has entered the shoe the value of MAASP can increase without any danger for the formation, provided that the bottom hole pressure is kept constant. The two different processes are explained in the following:

Liquid The influx does not expand during the upwards flow. The PHs decrease ends when the influx has completely entered the shoe.

Gas The influx expands during the upwards flow. The expansion determines a PHs decrease during the complete upwards flow, even after the influx has completely entered the shoe.

Fracture mud density

Definition The fracture mud density (DFR)allows us to represent the fracture pressure in terms of mud density so that we can have a reference value.

The DFR represents the mud density that in static conditions determines a pressure equal to the fracture pressure and can be calculated by the following formula:

DFR = PFR x 10 H

This value is equal to the maximum allowable mud density in the well.

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The allowable mud density in the well can vary from a minimum value, equivalent to the normal formation gradient GF, to a maximum value corresponding to the DFR, as shown in the following graph.

The MAASP can be a function of the DFR. In fact:

MAASP = P - PFR _H_s MAASP = DFR x Hs 10 -D x Hs 10 MAASP = ( DFR - D) x Hs 10 ___________________________________________________________________________________ Eni Corporate University

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1.7 PRESSURE LOSS (PL)

Definition It is the pressure required for circulating the mud in the well at a slow circulating rate. (The normal PL values are determinate at 1/2 and 1/3 of the normal flow rate).

The measurement and the recording of this value are of great importance, since they represent the circulating pressure to be used in case of kick.

PL is determined with the well closed and with circulation through the choke line. The choke line does not alter the PL value because its length is irrelevant where pressure losses are concerned. The PL values must be determined in order to:

(WHY)

• to control kick with the standard pump without exceeding its maximum working pressure.

• to weigh up and degasify the mud more easily

• to reduce wear and strain on surface equipment

• to reduce pressure losses in the annulus

• to work with one pump only

• to reduce stress on the staff performing the well control

The PL values must be recorded:

(WHEN)

• at the beginning of each operation

• if the mud density changes

• if the drilling string composition changes

• if the pump liner diameters change

• if the bit nozzles are changed

The PL value must be read:

(HOW)

• Routinely, doing two readings:

- at minimum number of pump strokes

- at 10 o 20 pump strokes above the minimum number of pump strokes

• for each pump separately

Note: - PL values must always be recorded on the drilling chart.

- PL values must be read from the gauge on the control panel of the automatic choke. Even with identical pumps the PL must be recorded for each pump since the volumetric efficiency can be different.

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In case of equal densities of the mud and of the hydraulic circuit (constants indicated by K in the following formula) the PL at a reduced flow rate is 1/4 of the normal pressure, since the circulation pressure depends on the square of the mud circulation flow rate:

∆P = k Q2

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1.8 SHUT-IN PRESSURES

When a kick sets in, the pressure values within the well are modified and stabilize at values which assure a new equilibrium between bottom hole pressure and formation pressure.

Once the well has been closed and the pressure values have stabilized, two specific pressures must be read in order to carry out the well control:

1 SIDPP (Shut In Drill Pipe Pressure), 2 SICP (Shut In Casing Pressure),

Shut In Drill Pipe Pressure

Definition The shut-in drill pipe pressure (SIDPP) is the pressure read at the pipes after stabilisation, with the well closed and during a kick.

SIDPP = P - P_F _H

Shut-in casing pressure

Definition The shut-in casing pressure (SICP) is the pressure read in the casing after stabilisation, with the well closed during a kick.

H

SICP = P - (PF HG + P ) where:

PHG = Hydrostatic pressure exerted by the fluid in the well

The relation between the two shut-in pressure values is of great importance. If in the place of PHG and PH we write their expression (density x height/10), we obtain:

SICP = SIDPP + (D - DG) ⋅ HG 10

Hence, we obtain the density of the mud (DG) inside the well:

DG = D - (SICP - SIDPP) X 10 HG

Depending on the DG value we can have the following situations:

• DG > 0,7 the fluid in the well is liquid

• 0,3 < DG < 0,7 the fluid in the well is a mixture

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1.9 CIRCULATING PRESSURE

Definition The circulating pressure is the pressure exerted on the pipes during the

well control.

During the operational stages of the well control we have two different circulating pressures:

ICP Initial circulating pressure which is the pressure at the start-up of the pump, with original mud (unweighted)

ICP = SIDPP + PL

FCP Final circulating pressure which is the value read on the gauge of the pipes when the Kill mud comes out of the bit and begins to replace the original mud in the annulus.

FCP = PL x KMD OMD

(KMD = density of the weighted mud)

(OMD = density of the original mud)

This different terminology is necessary for filling in the KILL SHEET.

Note The two pressures, ICP and FCP, can be increased by a safety margin factor which is not specified in the EWCF regulations.

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1.10 GAS LAW

The Ideal Gas Law, known also as Boyle's Law affirms that for a gas held at constant temperature, its volume multiplied by its pressure remains constant:

P x V = constant

The Perfect Gas Law can be considered sufficiently accurate also in the case of gas migration. In our case this means that during every phase of migration in the well the product of the volume by the pressure of influx gas remains constant.

Defining Pi e Vi as pressure and initial volume of the influx gas, P' e V' as pressure and volume of the influx gas in a given phase of the migration, we have:

P V = P' V'i⋅ i ⋅

Assuming the relation P x V = constant, we analyse the following situations:

• gas migration without expansion

• gas migration with uncontrolled expansion

• gas migration with controlled expansion

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1.11 GAS MIGRATION IN A CLOSED-IN WELL, WITHOUT EXPANSION

Let us analyse the behaviour of a gas influx that migrates in a well with the BOP closed. The gas cannot expand because the BOP has been closed and will therefore migrate in the annulus because of the difference between the gas specific weight and the mud specific weight .

Without expansion the gas volume and the gas pressure during the gas migration do not change (gas law).

The hydrostatic pressure at the top of the gas column decreases because of the upward movement and is compensated by an increase of pressure at the top. As a consequence, the bottom hole pressure will increase.

The aforesaid is represented in the following graphs:

From what we have already seen it is clear that simply keeping the well closed and waiting leads to high pressure values in the well which can cause:

• fracture of the formations with lost of mud and the possibility of subsequent uncontrolled underground blowouts

• damage to equipment

• breaking of the casing

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1.12 GAS MIGRATION IN AN OPEN WELL WITH UNCONTROLLED EXPANSION

In this case, with the BOP opened, the gas migrates upwards expanding freely and its volume increases.

This expansion results in the expulsion of an equal volume of mud with a subsequent decrease in the bottom hole hydrostatic pressure and additional gas can enter. The expansion is not substantial until the gas reaches the 3/4 of its upwards movement; the phenomenon becomes then more evident, with the expulsion of bigger volumes in shorter intervals

The following graphs are a representation of what has been said:

From what we have previously seen, it is evident that the upward movement of a gas influx in an open well is characterised by an uncontrolled expansion of gas volume causing:

• a decrease in the bottom hole pressure, due to the partial emptying of the annulus, with danger of additional gas influx;

• a situation which becomes more and more difficult to control.

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1.13 GAS MIGRATION IN A CLOSED-IN WELL WITH A CONTROLLED EXPANSION

The migration of gas without expansion causes an increase in bottom hole pressure, while the migration with uncontrolled expansion causes a reduction in bottom hole pressure. Both of these conditions can not be used in practice because they alter the bottom hole pressure .

Correct management of the rising gas influx must include a controlled expansion that will keep the bottom hole pressure constant at a pressure value which is equal to the formation pressure. We now proceed to analyse a gas influx migration in a closed-in well under controlled

expansion (the control shall be carried out operating on the choke)

During migration the gas expands, increasing in volume and consequently decreasing in pressure, and the gas expansion will displace a corresponding amount of mud producing a decrease in hydrostatic pressure, compensated by an increase in surface pressure. As a consequence, the bottom hole pressure remains constant.

What has been said is illustrated by the following graph:

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1.14 REPRESENTATION WITH A TUBE "U"

We can imagine a well in the form of a "U" tube with: - pipe branch

- annulus branch where:

- the pipe is open at the bottom

- the bottom is in contact with the formation

- the pipe branch is full of mud with density D, which exerts a pressure PH

- the annulus branch (in case of a kick) can contain in addition to mud also influx.

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Graphic representation of “U” tube principle:

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CAUSES OF

KICK

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GENERALITY

The main cause of a kick is the lack of an adequate hydrostatic pressure to assure : PH > PF

If, for some reason, it turns out that PH < PF we have reached the necessary and sufficient condition for a kick.

This condition can come about as a result of different causes which can be grouped as follows:

Natural causes Operative causes

Natural causes determine an increase in formation pressure.

Operative causes, or mechanically induce causes, determine a decrease in hydrostat pressure at the bottom hole.

They mainly consist of: They mainly consist of:

a) abnormal pressure b) failing to fill the hole properly when trippin out drill string

c) swabbing

d) loss of circulation e) insufficient mud weight f) gas-cut mud

At present, more than 50% of blow-outs are due to the combination of causes b) and c).

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2.1 ABNORMAL PRESSURE

An abnormal formation pressure will take place when fluid pressure in the formation has a gradient bigger than 1,07 kg/cm2/ 10 meters. By drilling trough an abnormal pressure formation with an insufficient mud weight a kick can be caused.

Abnormal pressures are caused by particular geological situations:

- high velocity in sedimentation Low permeability zones, sedimented at high velocity can trap fluids thus determining an abnormal pressure zone.

- abnormal pressure due to fault Sedimentation zones can be raised by tectonic movements. In this case the zone has kept its original pressure. A further erosion of the surface has determined a lesser depth of the zone, which, under normal conditions, would have a lower pressure than the pressure it has.

- artesian effect An artesian effect takes place when drilling through a water-bearing layer. In this case the pressure is not related to the drilling depth but is determined by the height of the water layer above the drilling point.

- lenses Lenses are found when impermeable zones (clay) produce

structural traps that imprison the formation fluids. Lenses near the surface are particularly dangerous.

- inclination of rock layers When the geometry of a gas reservoir is strongly inclined, the formation pressure values on the upper part of the lens are abnormal. The fluid layer pressure is normal, while, due to the low density of the gas, the pressure value in the higher region of the reservoir is abnormally high.

During the last years of research different methods have been studied in order to prevent abnormal pressures: some of them can be applied before the drilling, some during the drilling and some after the drilling. In spite of the validity of the principles they are based on, these methods might prove unreliable in certain situations, such as limited quantity of the samples to be analysed, subjective data evaluation, uncertainty about the depth of the sample original region.

The methods which are most commonly used during the drilling are: Trip velocity D exponent Sigmalog Clay density Clay resistivity Mud temperature

Mud resistivity, salinity and pH Gas manifestation

Slides and hole diameter reductions

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2.2 FAILING TO FILL THE HOLE PROPERLY WHILE TRIPPING - OUT

If the volume of the steel removed during the tripping out is not replaced by an equal volume of mud, we will have a decrease in the hydrostatic pressure throughout the well. In such conditions it is likely that, in a certain layer, the hydrostatic pressure is lower than the formation pressure in the same layer, causing the fluid to enter the well.

For this reason, the volume of the removed steel must always be replaced with an equivalent volume of mud.

V_{pulled out steel}_{= V}_{added mud volume}

This condition must always be verified to avoid drops in the bottom-hole hydrostatic pressure, and this must be done by means of the Possum belly, which points out even minor changes in the tank level. If the well receives less mud, this means that some formation fluid has entered inside the well.

Warning: this is one of the main causes of kick and it is essentially due to the driller's responsibility.

The decrease in pressure determined by the tripping out, can be calculated as follows: 1. Calculate the volume of the pulled-out steel

2. Calculate the drop in mud level in the hole 3. Calculate the drop in hydrostatic pressure 1) calculate the volume of the pulled-out steel

The two following situations should be considered when calculating this volume:

a) dry drill pipe: in this case only the volume of the pulled out steel must be considered: Pulled-out volume = [pulled-out length ] x [steel displacement]

b) wet drill pipe: in this case the pulling out of the total volume of the pipes must be considered, and such volume is given by the closed-end displacement plus the casing capacity.

Pulled out volume = [pulled-out length] x [closed-end displacement]

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2) calculation of the drop in the mud level inside the well ∆H

For this calculation, two other cases should be considered besides the wet and dry drill pipes cases: the presence of the pipes inside the well and the pulling out of the last drill pipe.

pipes inside the well:

a) dry drill pipe ∆ H =

volume pulled out

casing capacity - steel displacement

b) wet drill pipe ∆ H =

volume pulled out

casing capacity - closed end displacement

last drill pipe ∆ H = volume pulled out

casing capacity

3) calculation of the drop in hydrostatic pressure ∆PH

∆ PH = mud density x drop in level

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2.3 SWABBING

The drill string movement determines a mud flow in the annulus and such flow determines on its turn a pressure loss and a subsequent variation in the bottom hole pressure. This phenomenon is called swabbing.

In case of tripping out, pressure losses inside the annulus (Swabbing)determine a decrease in the bottom hole pressure:

PB = PH - ∆Pan

The drop in the bottom hole pressure can determine the entrance of formation fluids.

In case of tripping in the hole the pressure losses (Surging) are added to the hydrostatic pressure: PB = PH + ∆Pan

The increase in the bottom hole pressure might determine a fracture in the formation with subsequent pressure loss and danger of a kick.

The danger of a kick is much higher during the tripping out than during the tripping in. The swabbing effect becomes greater as the following entities increase:

• trip velocity

• decrease in annulus clearance

• length of the drill string in the hole

• mud viscosity

The phenomenon is also amplified by the presence of clay obstructions on the bit and on the stabilizers (obstructions in the Bottom Hole Assembly) because they narrow the hole.

The phenomenon increases linearly with depth and is at its maximum when the bit is near the bottom (increase in the string length>>>increase in pressure losses>>>increase in swabbing). In this case the trip velocity must be reduced.

The onset of swabbing can be detected through the Possum Belly. By observation of the mud level, we can know if formation fluids have entered the well during the tripping out.

A change in the string weight, detected through the Martin Decker during the trip, usually intensifies the swabbing effect.

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In order to prevent and reduce the effect of swabbing the following indications should be followed: - decrease trip velocity (especially near the bottom)

The trip velocity determines the pressure loss values due to swabbing. The swabbing effect increases sharply with trip velocity

- condition the mud, carefully checking the rheological characteristics

Improving the rheological characteristics of the mud before the tripping reduces the swabbing effect and facilitates tripping operations

- pay the utmost attention in case of overpull during a trip

Overpull during trip can worsen swabbing. The operation must be done with care. - increase in mud density

Mud density can be increased to bring trip margin back to its previous level - Short Trip

Procedure:

• pull out some stands at normal velocity • run in again to the bottom

• circulate the bottom influx up to the surface

• analyse the characteristics of the mud and of any influx pulled out: . if the mud is not gas-cut, you can pull out with the same velocity

. if the mud is gas-cut, you must determine the type of operation necessary

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The two graphs below illustrate the variations of trip velocity and of PB during a trip:

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2.4 LOSS OF CIRCULATION

The term "loss of circulation" indicates a flow of mud from the well towards the formation, caused by naturally fractured formations or by mechanically induced fractures (for example by swabbing).

The loss of circulation can be:

• partial: when the flow-out is less than the flow-in

• total: when there is no return of mud from the well, causing a sudden drop in the level inside the well

Total loss of circulation can cause a kick because the mud level in the well drops, thus determining a drop in the hydrostatic pressure; mineral layers previously controlled by the mud, may cause a kick.

Partial loss alone is not a direct cause of kick. But if it worsens, it may reach a total loss value. The loss of circulation can be caused by:

- geological causes:

.karsic formations

.fractured formations

.faults

- operative conditions that can take place inside the well:

. substantial pressure losses in the annulus . swabbing during tripping in (surge pressure)

. starting of circulation through holes of small diameter at great depth . gumbo shale in the annulus

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2.5 DECREASE OF MUD DENSITY

The hydrostatic pressure exerted by the column of mud in the well is the main condition for the prevention of a kick. If the mud density decreases when passing through mineral layers (due to unforeseen causes), the hydrostatic pressure in the well will drop below planned levels and as a consequence some formation fluids might enter in the well.

The most common causes of an unplanned decrease in mud weight are: - defective functioning or failure of the mud surface equipment.

- erroneous mud circuit operations - unsuitable characteristics of the mud

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2.6 GAS-CUT MUD

When a structure containing gas is drilled, a certain quantity of gas is released in the drilled rock volume. The mud forms an emulsion with the gas and its density decreases. The gas released inside the well is subject to the hydrostatic pressure of the mud column over it. As soon as the gas starts to flow upwards (either because of the circulation or of the difference in density) the pressure over it decreases, and the gas expands.

The decrease in mud density is minimal at the bottom and greater at the surface, with a slight decrease of the bottom hole pressure.

The quantity of gas released when a gas-bearing formation is drilled determines a continuous contamination of the mud (background value) which depends on the following factors:

- drilling rate

- degree of porosity of the formation - hole diameter

The presence of gas in the mud during drilling operations, depending on the operational conditions, can be defined as follows:

a) Drilling gas: gas released from the rock by the penetration of the bit

b) Connection gas: gas which accumulates in the well during pauses for adding the pipes (connection)

c) Trip gas: gas which accumulates during pauses to change bit. (The pause is much longer and the accumulation is greater).

d) Formation gas: formation gas penetrated in the well when the hydrostatic pressure value is not high enough to compensate the formation pressure value.

The drilling gas, the connection gas and the trip gas, at an initial stage of the drilling, all have a pressure value lower than the hydrostatic pressure value:

Pgas < PH

The well control is guaranteed and the situation is under control. As a general rule, these situations are not dangerous. They may become dangerous if the volume of the penetrated gas is high. This could happen at the initial stage of the drilling operations, with large diameters and high drilling velocity. In this case we talk about Shallow gas.

Instead, in a situation where

Pgas > PH we have formation gas, and a kick takes place.

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The danger resulting from mud contamination, that is the decrease of the hydrostatic pressure (∆PH) due to the rapid expansion of the gas at the surface, can be determined either by empirical tables or analytically, using the following formula:

∆ P = 2,3 x x log PH D - D

D1 H

1

where: _{PH = hydrostatic bottom pressure with mud density D} D = original mud density

D1 = gas-cut mud density

Gas accumulations are read by the Gas Detector. The Degasser is used to expel gas from the mud before circulating it in the well again.

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2.7 PARTICULAR SITUATIONS

A kick can be determined by a simultaneous combination of phenomena or as a consequence of certain operations which normally do not cause blow-out.

In the following are some of these situations: • layer test (DST)

• running a casing

• recording of electrical logs

• waiting for cement hardening after the casing job • some conditions for fishing

• retrieve of a Bridge Plug slightly below the surface

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2.8 SYNTHESIS

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KICK

INDICATORS

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GENERALITY

It is very important to recognise a kick at an early stage. Experience shows that the more limited the initial volume of the contaminating fluid, the higher the possibility to carry out a successful control.

The aim of this chapter is that of examining the main kick indicators. However, in the operational practice, the phenomenon determines more than one change simultaneously. For this reason, a careful analysis of such combination of phenomena helps detecting abnormal situations. Kick indicators can be grouped into two categories, as shown by the following chart:

INDICATORS OF A KICK IN PROGRESS

INDICATORS OF POSSIBLE KICK

Flow rate increase Pit volume increase

Hole keeps flowing with pumps stopped Increase of penetration rate

Lesser decrease of the mud level during pulling out operations

Decrease in circulating pressure and increase in pump strokes

Gas-cut mud

Decrease in string weight and increase in pressure

Increase in torque and/or overpull

The indicators are listed according to their priority level. In the right-side column the last three indicators refer to particular situations. The quantity of fluid which can penetrate in the well is in direct proportion with the negative value of the pressure difference PH-PF , with the formation permeability, with the length of the drilled section and with the time required to recognise the kick. It is therefore very important that a kick be recognised immediately, promptly carrying out ___________________________________________________________________________________ Eni Corporate University

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the necessary checks and operations. The prompt detection of a kick is the driller's main aim.

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3.1 FLOW RATE INCREASE

In normal conditions the quantity of mud coming out of the well is equivalent to that entering it and corresponds to the flow rate of the pump.

The entry of formation fluid in the well alters this equilibrium and causes an increase in flow-out. This variation can be read on a flow meter positioned on the flow line.The flow meter indicates flow variations and being connected to the flow line, enables us to recognise kick immediately.

3.2 HOLE KEEPS FLOWING WITH PUMPS STOPPED

This is a sure indicator that a kick is in progress. It takes place when the annular pressure losses are significant (especially in the small diameter holes).

In this case, by stopping the circulation, the annular pressure losses will stop too. The formation pressure can exceed the hydrostatic pressure and, as a consequence, formation fluids will enter into the well.

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3.3 PIT VOLUME INCREASE

Any flow of formation fluid into a well determines an increase in the surface mud volume. This means that an increase in pit volume is a kick indicator. In this case it is necessary to stop operations and carry out a flow check.

If no kick is detected, check the reason for the anomaly. (The foreman should always be informed about the operations which can modify the pit volume in order to avoid the start of unnecessary checks).

The acoustic alarm for indicating pit volume variations must always be in working condition and ready to show even slight level changes.

A pit volume increase can also depend on other causes, not related to the kick. The most important ones are :

• addition of materials to modify the mud characteristics

• leakage or incorrect use of mud system valves which can cause the transfer between the tanks .

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3.4 INCREASE IN PENETRATION RATE (DRILLING BREAK)

The rate of bit penetration tends to decrease as the depth of the well increases because of increasing hardness of the ground. A sharp increase of the penetration rate can indicate entry into a zone of abnormal pressure. In such a situation it is necessary to stop drilling and run a flow check for kick.

The graph shows the trend of the formation pressure gradient with respect to the mud gradient. It also points out that the entry into an abnormal pressure zone alters the hydrostatic equilibrium and a subsequent kick.

The graph below shows the trend of the difference DP between the bottom hole pressure and the formation pressure. During drilling, the DP value is positive. Approaching to the abnormal pressure zone such value decreases until it reaches negative values when the bit impacts the abnormal pressure zone. This phenomenon might depend on the rock higher softness.

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3.5 LESSER DECREASE OF THE MUD LEVEL IN THE POSSUM BELLY DURING THE TRIPPING - OUT OPERATIONS

During the trip out of the hole the level in the possum belly can decrease less than expected because of the volume of the pulled out steel. This can imply that swabbing is taking place and that there can be some formation fluid in the well, partially compensating the decrease in level.

In this case tripping out must be suspended and you must carry out a flow check, which can reveal three different situations:

1) a return to normal level This is not a dangerous situation. The lesser drop was due to a partial obstruction in the annulus.

2) a lower than expected level

The swabbing has determined a momentary unbalance of the bottom hole pressure and a subsequent entry of limited quantity of formation fluid.

The Equilibrium is restored by suspending movement, even though some fluid remains inside the well and the level in the tank is different. In this case, stop the trip.

3) the well keeps flowing Kick in progress!

In order to determine the degree of swabbing during the tripping out, an accurate check of the level variations in the possum belly is recommended.

Note The use of the possum belly also during the trip-in operations allows to detect abnormal conditions in the well, such as the migration of a gas influx or the fracturing of a weak formation.

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3.6 DECREASE OF CIRCULATING PRESSURE AND INCREASE OF PUMP STROKES

The formation fluids, compared to mud, are usually characterised by a lower density. Therefore, their penetration into the well determines a decrease of the annulus hydrostatic pressure and a subsequent unbalance in the well. Such unbalance determines a decrease of the circulating pressure and possibly an increase of the pump strokes.

These conditions may indicate that a kick is taking place and it is therefore necessary to interrupt all the operations and adopt the recommended procedures.

The decrease of the circulating pressure may also be due to other causes such as:

• pump failure

• unbalanced mud

• wash-out of the drill string.

In any case, a kick should be included among the possible reasons for a pressure decrease until the actual cause has been detected.

Note The increase of the pump strokes is more evident in mechanical (or diesel electric) systems than in SCR systems.

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3.7 GAS-CUT MUD

The presence of formation fluid in the well can be detected by continuous observation of some chemical-physical characteristics of the mud such as density, salinity, content of chlorides. Such readings reveal the presence of formation fluids:

density The mud density will decrease as the formation fluids penetrate into the well.

content of chlorides An increase in chlorides in the mud fluid indicates the entrance of native water. In fact, the salinity in water formation is usually greater than that in drilling mud.

The increase of such values, revealed by continuous monitoring, may reveal a progressive increase of the formation pressure or a decrease of the tripping margin and can therefore supply useful information to prevent kicks.

The mud can be contaminated by:

• water

• oil

• gas

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3.8 OTHER INDICATORS OF A KICK

A) Decrease in the drill string weight and increase in the circulating pressure

A decrease in the drill string weight, indicated by the Martin Decker weight indicator, and an increase in the circulating pressure indicate a kick. In fact, the pressure of the fluid infiltrated into the well exerts a mechanical force that tends to push the drill string upwards. Such mechanical force is also exerted on the pipes mud opening the pump safety valves so that the fluid cannot penetrate inside the pipes.

This is a rare phenomenon that can arise with high formation pressure and high permeability.

Note A sudden increase in circulating pressure can open the safety valve of the pump with return flow from the pipes.

B) Increase in torque and/or overpull

In particular conditions the formation pressure tends to reduce the hole opening with a consequent increase in torque during drilling and in overpull during the pipe changing operations.

These conditions can reveal the beginning of a kick.

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3.9 SYNTHESIS OF KICK INDICATORS

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SHUT - IN

PROCEDURES

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