Well Control Eni Manual

Eni Corporate University

WELL CONTROL Training course based upon the contents of the

Multimedia course on well control

INDEX

1. PRESSURES AND GENERAL PRINCIPLES 1.1 1.2 1.3 1.4 1.5 1.6 1.7 1.8 1.9

Hydrostatic pressure Static pressure Pressure losses Bottom hole pressure Formation pressure Fracture pressure Pressure loss (slow circulating pressure) Shut-in pressures Circulating pressure

1.10 1.11 1.12 1.13 1.14

Gas law Gas migration in a closed-in well, without expansion Gas migration in an open well with uncontrolled expansion Gas migration in a closed-in well with a controlled expansion Representation with a tube "U"

2. CAUSES OF KICK 2.1 2.2 2.3 2.4 2.5 2.6 2.7 2.8

Abnormal pressure Failing to fill the hole properly while tripping - out Swabbing Loss of circulation Decrease of mud density Gas-cut mud Particular situations Synthesis

1 3 7 8 20 23 24 28 30 31 32 33 34 35 36

39 42 43 45 48 49 50 52 53

3. KICK INDICATORS 3.1 3.2 3.3 3.4 3.5 3.6 3.7 3.8 3.9

Flow rate increase Hole keeps flowing with pumps stopped Pit volume increase Increase in penetration rate (drilling break) Lesser decrease of the mud level during the tripping- out operations Decrease of circulating pressure and increase of pump strokes Gas-cut mud Others indicators Synthesis

4. SHUT-IN PROCEDURES 4.1 4.2 4.3 4.4 4.5 4.6 4.7

Well shut - in procedures: soft shut-in and hard shut-in Shut-in during drilling Shut-in during tripping: with drill pipes Shut-in during tripping: with drill collars Warnings Crew drill Stabilization of the SIDPP and SICP pressure values

5. WELL CONTROL METHODS 5.1 5.2 5.3 5.4 5.5 5.6 5.7 5.8

Driller's method Pressure at the shoe Wait and weight method Considerations on driller's method and wait and weight method Volumetric method Lubrication Stripping or snubbing Analysis of the main problem that occur during well control

55 58 58 59 60 61 62 63 64 65

67 69 71 72 73 74 75 76

81 84 90 93 98 100 103 105 106

Pressure and general principles _______________________________________________________________________________________________________

PRESSURE AND GENERAL PRINCIPLES

___________________________________________________________________________________ Eni Corporate University

1

WELL CONTROL _______________________________________________________________________________________________________

2

_______________________________________________________________________________________ Eni Corporate University

Pressure and general principles _______________________________________________________________________________________________________

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/cm2.

1.1 HYDROSTATIC PRESSURE ( PH ) 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 PH

Defining:

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

the hydrostatic pressure PH is defined by the following expression: PH =

D × H 10

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] [kg] = 100 cm x [l] [1000 cm 3 ]

=

1 [kg] x 10 [cm 2 ]

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

___________________________________________________________________________________ Eni Corporate University

3

WELL CONTROL _______________________________________________________________________________________________________

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 PH 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

PH

kg/cm2

bar

kPa

psi

10

0,0981

0,00981

0,052

DxH 10

D x H x 0,0981

D x H x 0,00981

D x H x 0,052

Pressure

Conversion Factor

Formula for the calculation of PH

4

_______________________________________________________________________________________ Eni Corporate University

Pressure and general principles _______________________________________________________________________________________________________

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

From the metric system to the English system:

kg/cm2 : 0.0703 = psi

= kPa

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 PH 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: PH =

D x H 10

=

1, 5 x 4.000 = 600 kg/cm2 10

The hydrostatic pressure can be described by the following diagram:

___________________________________________________________________________________ Eni Corporate University

5

WELL CONTROL _______________________________________________________________________________________________________

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=

D PH = 10 H

The gradient is expressed in kg/cm2 per metre: Kg ⋅ m cm 2 In practical work, the unit of the gradient is not 1 metre, but 10 metres. Thus:

G=

P D x H x 10 = 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:

PH = H ⋅ G

6

_______________________________________________________________________________________ Eni Corporate University

Pressure and general principles _______________________________________________________________________________________________________

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 PS =100 kg/cm2 , the graphic description of the pressure within the well is as follows:

___________________________________________________________________________________ Eni Corporate University

7

WELL CONTROL _______________________________________________________________________________________________________

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 8

_______________________________________________________________________________________ Eni Corporate University

Pressure and general principles _______________________________________________________________________________________________________

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

___________________________________________________________________________________ Eni Corporate University

9

WELL CONTROL _______________________________________________________________________________________________________

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

10

_______________________________________________________________________________________ Eni Corporate University

Pressure and general principles _______________________________________________________________________________________________________

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

___________________________________________________________________________________ Eni Corporate University

11

WELL CONTROL _______________________________________________________________________________________________________

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:

∆P=

12

table value 100

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

_______________________________________________________________________________________ Eni Corporate University

Pressure and general principles _______________________________________________________________________________________________________

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

___________________________________________________________________________________ Eni Corporate University

13

WELL CONTROL _______________________________________________________________________________________________________

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:

∆P=

14

table value 100

x drill collars length x mud density

_______________________________________________________________________________________ Eni Corporate University

Pressure and general principles _______________________________________________________________________________________________________

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

x drill pipes length x mud density

___________________________________________________________________________________ Eni Corporate University

15

WELL CONTROL _______________________________________________________________________________________________________

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.

16

_______________________________________________________________________________________ Eni Corporate University

Pressure and general principles _______________________________________________________________________________________________________

Example: Clculation of pressure losses Hole Depth DPs 5" E DCs 8" x 12 13/16 " RB Mud density (D) Flow rate (Q)

∅ = 12 ¼ " 3000 mt 2850 mt 150 mt 3 x ½" 1,4 kg/lt 2300 lt/min

SURFACE PIPING SYSTEM (Tab. n° 1) Q = 2300 --------------------> ∆P = 3,6 Kg/cm2 ∆P = 3,6 x 1,4 = 5 Kg/cm2

(D = 1,00) (D = 1,4)

INSIDE DPS (Tab. n° 2) Q = 2300 → ∆P = 1,6 Kg / cm2 for 100 mt ∆P (DPs length) ∆P = 45,6 × 1,4 = 63,84

2850 × 1,6 = 45,6 Kg / cm2 (D = 1,00) 100 64 Kg / cm2 (D = 1,4) → →

INSIDE DCS (Tab. n° 3) Q = 2300 → ∆P for 100 mt = 11,5 Kg / cm2 150 ∆P for 150 mt = × 11,5 = 17,25 Kg / cm2 (D = 1,00) 100 ∆P (D = 1,4) = 17,25 × 1,4 = 24,15 → 24 Kg / cm2 ANNULUS DC - HOLE (Tab. n° 5) Q = 2300 → ∆P for 100 mt = 0,19 Kg / cm2 150 ∆P for 150 mt = × 0,19 = 0,28 Kg / cm2 (D = 1,00) 100 ∆P (D = 1,4) = 0,28 × 1,4 = 0,39 → 0,4 Kg / cm2

___________________________________________________________________________________ Eni Corporate University

17

WELL CONTROL _______________________________________________________________________________________________________

ANNULUS DP - HOLE (Tab. n° 7) Q = 2300 → ∆P for 100 mt = 0,056 kg / cm2 2850 ∆P for 2850 mt = × 0,056 = 1,59 kg / cm2 (D = 1,00) 100 ∆P (D = 1,4) = 1,59 × 1,4 = 2,23 → 2,2 kg / cm2

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

18

_______________________________________________________________________________________ Eni Corporate University

Pressure and general principles _______________________________________________________________________________________________________

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.

PBH = PH + ∆Pan

Exemple 1: Hole Depth DPs 5" E DCs 8" x 12 13/16 " Mud density (D) Flow rate (Q)

∅ = 12" ¼ 3000 mt 2850 mt 200 mt 1,5 kg/lt 2200 lt/min

Exemple 2:

∅ = 8" ¼ 3000 mt 2800 mt 200 mt 1,5 kg/lt 2200 lt/min

Hole Depth DPs 5" E DCs 6" ½ x 12 13/16 Mud density (D) Flow rate (Q)

∆Pan = 2,77 kg/cm2

∆Pan = 18,75 kg/cm2

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

___________________________________________________________________________________ Eni Corporate University

19

WELL CONTROL _______________________________________________________________________________________________________

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. 2. 3. 4.

Open well and pump turned off Open well with circulation Closed well and pump turned off 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 20

_______________________________________________________________________________________ Eni Corporate University

Pressure and general principles _______________________________________________________________________________________________________

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

___________________________________________________________________________________ Eni Corporate University

21

WELL CONTROL _______________________________________________________________________________________________________

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

22

_______________________________________________________________________________________ Eni Corporate University

Pressure and general principles _______________________________________________________________________________________________________

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

x 100

rock volume

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 if if

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

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:

___________________________________________________________________________________ Eni Corporate University

25

WELL CONTROL _______________________________________________________________________________________________________

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.

26

_______________________________________________________________________________________ Eni Corporate University

Pressure and general principles _______________________________________________________________________________________________________

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 = PFR

MAASP = MAASP =

-

DFR x Hs 10

P Hs -

D x Hs 10

( DFR- D) x Hs 10

___________________________________________________________________________________ Eni Corporate University

27

WELL CONTROL _______________________________________________________________________________________________________

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.

28

_______________________________________________________________________________________ Eni Corporate University

Pressure and general principles _______________________________________________________________________________________________________

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 Q 2

___________________________________________________________________________________ Eni Corporate University

29

WELL CONTROL _______________________________________________________________________________________________________

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 2

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

‰

Shut In Drill Pipe Pressure

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

Definition

SIDPP = PF - PH ‰

Shut-in casing pressure

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

Definition

SICP = PF - (PHG + PH ) 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: • • • 30

DG > 0,7 0,3 < DG < 0,7 DG < 0,3

the fluid in the well is liquid the fluid in the well is a mixture the fluid in the well is gas

_______________________________________________________________________________________ Eni Corporate University

Pressure and general principles _______________________________________________________________________________________________________

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.

___________________________________________________________________________________ Eni Corporate University

31

WELL CONTROL _______________________________________________________________________________________________________

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: Pi ⋅ Vi = P' ⋅V'

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

32

•

gas migration without expansion

•

gas migration with uncontrolled expansion

•

gas migration with controlled expansion

_______________________________________________________________________________________ Eni Corporate University

Pressure and general principles _______________________________________________________________________________________________________

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

___________________________________________________________________________________ Eni Corporate University

33

WELL CONTROL _______________________________________________________________________________________________________

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: • •

34

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.

_______________________________________________________________________________________ Eni Corporate University

Pressure and general principles _______________________________________________________________________________________________________

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:

___________________________________________________________________________________ Eni Corporate University

35

WELL CONTROL _______________________________________________________________________________________________________

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.

36

_______________________________________________________________________________________ Eni Corporate University

Pressure and general principles _______________________________________________________________________________________________________

Graphic representation of “U” tube principle:

___________________________________________________________________________________ Eni Corporate University

37

WELL CONTROL _______________________________________________________________________________________________________

38

_______________________________________________________________________________________ Eni Corporate University

Causes of kick _______________________________________________________________________________________________________

CAUSES OF KICK

___________________________________________________________________________________ Eni Corporate University

39

WELL CONTROL _______________________________________________________________________________________________________

40

_______________________________________________________________________________________ Eni Corporate University

Causes of kick _______________________________________________________________________________________________________

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).

___________________________________________________________________________________ Eni Corporate University

41

WELL CONTROL _______________________________________________________________________________________________________

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 waterbearing 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 42

_______________________________________________________________________________________ Eni Corporate University

Causes of kick _______________________________________________________________________________________________________

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. Vpulled out steel = Vadded 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]

___________________________________________________________________________________ Eni Corporate University

43

WELL CONTROL _______________________________________________________________________________________________________

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: volume pulled out

∆H=

a) dry drill pipe

casing capacity - steel displacement

b) wet drill pipe

volume pulled out

∆H=

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 10

44

_______________________________________________________________________________________ Eni Corporate University

Causes of kick _______________________________________________________________________________________________________

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.

___________________________________________________________________________________ Eni Corporate University

45

WELL CONTROL _______________________________________________________________________________________________________

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

46

_______________________________________________________________________________________ Eni Corporate University

Causes of kick _______________________________________________________________________________________________________

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

___________________________________________________________________________________ Eni Corporate University

47

WELL CONTROL _______________________________________________________________________________________________________

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:

•

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

when the flow-out is less than the flow-in

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

48

_______________________________________________________________________________________ Eni Corporate University

Causes of kick _______________________________________________________________________________________________________

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

___________________________________________________________________________________ Eni Corporate University

49

WELL CONTROL _______________________________________________________________________________________________________

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.

50

_______________________________________________________________________________________ Eni Corporate University

Causes of kick _______________________________________________________________________________________________________

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:

∆ PH = 2,3 x

D - D1

x log PH

D1 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.

___________________________________________________________________________________ Eni Corporate University

51

WELL CONTROL _______________________________________________________________________________________________________

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: • • • • • •

52

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

_______________________________________________________________________________________ Eni Corporate University

Causes of kick _______________________________________________________________________________________________________

2.8 SYNTHESIS

___________________________________________________________________________________ Eni Corporate University

53

WELL CONTROL _______________________________________________________________________________________________________

54

_______________________________________________________________________________________ Eni Corporate University

Kick indicators _______________________________________________________________________________________________________

KICK INDICATORS

___________________________________________________________________________________ Eni Corporate University

55

WELL CONTROL _______________________________________________________________________________________________________

56

_______________________________________________________________________________________ Eni Corporate University

Kick indicators _______________________________________________________________________________________________________

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

57

WELL CONTROL _______________________________________________________________________________________________________

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

58

_______________________________________________________________________________________ Eni Corporate University

Kick indicators _______________________________________________________________________________________________________

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 flowout. 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.

___________________________________________________________________________________ Eni Corporate University

59

WELL CONTROL _______________________________________________________________________________________________________

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 : • •

60

addition of materials to modify the mud characteristics leakage or incorrect use of mud system valves which can cause the transfer between the tanks .

_______________________________________________________________________________________ Eni Corporate University

Kick indicators _______________________________________________________________________________________________________

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.

___________________________________________________________________________________ Eni Corporate University

61

WELL CONTROL _______________________________________________________________________________________________________

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.

62

_______________________________________________________________________________________ Eni Corporate University

Kick indicators _______________________________________________________________________________________________________

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.

___________________________________________________________________________________ Eni Corporate University

63

WELL CONTROL _______________________________________________________________________________________________________

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: • • •

64

water oil gas

_______________________________________________________________________________________ Eni Corporate University

Kick indicators _______________________________________________________________________________________________________

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.

___________________________________________________________________________________ Eni Corporate University

65

WELL CONTROL _______________________________________________________________________________________________________

3.9 SYNTHESIS OF KICK INDICATORS

66

_______________________________________________________________________________________ Eni Corporate University

Shut-in procedures _______________________________________________________________________________________________________

SHUT - IN PROCEDURES

___________________________________________________________________________________ Eni Corporate University

67

WELL CONTROL _______________________________________________________________________________________________________

68

_______________________________________________________________________________________ Eni Corporate University

Shut-in procedures _______________________________________________________________________________________________________

4.1 WELL SHUT-IN PROCEDURES: SOFT SHUT-IN AND HARD SHUT-IN After detecting any kick indicator, and when there is no doubt that a kick is taking place, the driller shall immediately carry out the well shut-in procedure following the recommended procedure. If there are any uncertainties, a flow check shall be carried out before starting the shut-in procedures. Flow check The flow check procedure can be done during drilling or during tripping. •

DURING DRILLING - Raise the kelly and the first tool joint with pumps on - Stop the pumps - Check any possible flow inside the well

•

DURING TRIPPING - Stop tripping - Check any possible flow from the well by means of the possum belly

The check for any flow from the well may determine two situations: - the well flows: - the well does not flow:

carry out the shut-in procedure resume the operations in compliance with the customer's instructions

After the need to shut the well has been ascertained, one of the two recommended procedures (API RP 59 regulations) can be chosen: 1) HARD SHUT- IN Procedure

2) SOFT SHUT- IN Procedure

The two shut-in procedures differ for the sequence of the following operations: • closing of the BOP • opening of the hydraulic valve on the choke line • possible closing of the power choke on the choke manifold The type of procedure is chosen in advance by the company and it depends on how the power choke has been set at the beginning of the operations: HARD procedure ---> closed power choke

SOFT procedure ---> partially open power choke

It is very important to verify periodically if the position of the valves on the choke manifold is in accordance with the type of procedure that has been chosen. The well shut-in implies a high risk of formation fracture at the casing shoe. In particular, the danger is greater at a limited depth because of the low fracturing formation gradient typical of this depth . ___________________________________________________________________________________ Eni Corporate University

69

WELL CONTROL _______________________________________________________________________________________________________

SOFT SHUT-IN procedure Before starting any operation make sure that the choke manifold is set to circulate the mud to the shale shaker through the half opened power choke and that the internal mechanical valve is open. Operational sequence to be followed: 1. Opening of hydraulic valve on the choke line 2. Closing of BOP 3. Closing of power choke 4. Recording of the stabilised SIDPP and SICP values and of the pit gain HARD SHUT-IN procedure (The choke must be set in the close position) 1. Closing of BOP 2. Opening of hydraulic valve on the choke-line 3. Recording of the stabilised SIDPP and SICP values and of the pit gain

SOFT Procedure

HARD Procedure

Advantages

Advantages

It allows an easier control of the casing pressure by reducing the danger of fracture below the casing shoe

It requires less time to carry-out the necessary operations with less formation fluid in the well

The opening of the hydraulic valve on the A lower fluid volume results in a lower SICP choke-line allows, on certain check panels, to keep the automatic opening system of the choke working

Reduction in water hammering phenomenon due to the immediate shut-in

Disadvantages

It is easier and quicker

Disadvantages

A bigger formation fluid volume will enter into Greater risk of fracturing the formation below the casing shoe the well

The Soft or Hard shut-in procedures ends with a series of operations to be carried out before and after the actual shut-in. Such operations are strictly connected with the operational stage, drilling (bit at the bottom), tripping with drill pipes or with the bit on the bottom, as it is shown in the following charts. 70

_______________________________________________________________________________________ Eni Corporate University

Shut-in procedures _______________________________________________________________________________________________________

4.2

WELL SHUT-IN DURING DRILLING

___________________________________________________________________________________ Eni Corporate University

71

WELL CONTROL _______________________________________________________________________________________________________

4.3

WELL SHUT-IN DURING TRIPPING, WITH DRILL PIPES

Two inside BOPs are being used: a gray valve and a lower kelly cock, the latter kept in reserve on the rig floor. Inside BOPs must be kept in good condition, in open position and handy on the rig floor. The keys for working on the installed kelly cocks and on the the kelly cock kept in reserve must always be at hand. If the gray valve has been installed to read the SIDPP, you must go ahead with the appropriate procedure (see stabilization of pressures).

72

_______________________________________________________________________________________ Eni Corporate University

Shut-in procedures _______________________________________________________________________________________________________

4.4

WELL SHUT-IN WHILE TRIPPING, WITH DRILL COLLARS

___________________________________________________________________________________ Eni Corporate University

73

WELL CONTROL _______________________________________________________________________________________________________

4.5 WARNINGS

During the well shut-in operations the following warnings should always be kept into account:

Closing the power choke

If the choke that has been installed doesn't seal perfectly, to obtain pressure balance you must close the choke up stream valve.

Installing the kelly cock

The keys for opening and closing the kelly cocks must always be at hand.

Installation of x-overs

The x-overs needed to connect the "inside BOPs" to the drill collars being used must be kept available on the rig floor.

Maintenance of “ inside BOPs”

The inside BOPs must be kept in good conditions, in the open position and handy on the rig floor.

74

_______________________________________________________________________________________ Eni Corporate University

Shut-in procedures _______________________________________________________________________________________________________

4.6 CREW DRILL In order to keep the crew at a high level of efficiency and to test the correctness of the procedures, some practice drills are periodically carried out. Such drills start without any advice and the crew operates as if it were a real situation or emergency case. Pit drill

The drill consists of a simulated change in the pit level. The level indicators are manually triggered thus activating the alarm; the crew must start the suitable procedures immediately. The drill is proposed by the supervisor before shutting in the well. The time is read to test the crew efficiency (the time required must no more than one minute).

Bop drill

It includes all the pit drill operations plus the well shut-in. At the beginning this drill is carried out quite frequently, until the crew reaches an acceptable execution time (two minutes). Subsequently, it becomes a weekly drill. The exercise varies depending on the operational conditions as follows: - during drilling - during tripping with drill pipes - during tripping with drill collars - with pipes outside the well Depending on the conditions under which the drill is carried out, the crew shall carry out the well shut-in in compliance with the corresponding procedure.

Stripping drill This test is carried out after the casing has been run in and before drilling the cement. It involves the closing of the BOP with the pipes inside the well, tripping them in according to the stripping procedure (see chapter on well control methods). The drill should take enough time to allow the running in of an adequate section of pipes for the testing of the equipment efficiency, and to let each member of the crew to learn his own task. Choke drill

This drill should be carried out before drilling the shoe, with the well closed and with trapped pressure. It consists of pumping through the pipes at a suitable flow rate, working on the choke in order to control the casing pressure. This exercise trains the crew to operate on the choke.

___________________________________________________________________________________ Eni Corporate University

75

WELL CONTROL _______________________________________________________________________________________________________

4.7 STABILIZATION OF THE SIDPP AND SICP PRESSURE VALUES When a kick occurs, the formation pressure (PF) near the bottom of the well decreases as a consequence of the formation fluid flow in the well. The formation pressure tends to decrease until it reaches the hydrostatic pressure value PH. After the well shut-in, a further formation fluid flow occurs at the bottom of the well: the time required depends on the formation permeability, on the fluid nature and volume, on the difference between PF and PH.

As a consequence, the surface pressures increase to such a value that added to their respective hydrostatic pressures, they develop a bottom hole pressure equal to the formation pressure. At this point the two pressures stabilise at their respective values. The time necessary for SIDPP and SICP to reach their final value is a period defined as "stabilisation time" (generally from 5 to 10 minutes). The increase in surface pressure must be followed attentively and recorded so that the exact moment of pressure stabilisation can be recognised. The true SIDPP and SICP values to consider for all following control operations are those of the moment of stabilisation.

A

B

Notes to the graphs: A-B: bottom hole pressure < formation pressure B: bottom hole pressure = formation pressure 76

C

B: stabilisation point

_______________________________________________________________________________________ Eni Corporate University

Shut-in procedures _______________________________________________________________________________________________________

The stabilisation time, after shutting in the well, is connected to the formation flow and depends on: • • •

degree of formation permeability nature and volume of contaminating fluid difference between PB and PF

The stabilisation process can follow different trends, depending on: • •

the nature of the contaminating fluid the degree of formation permeability

It is very important to know the exact SIDPP and SICP values because: •

the SIDPP value enables us to calculate the weighted mud density necessary for controlling kick;

•

the difference between SICP and SIDPP, together with the volume increase of the mud in the pit, enable us to determine the nature of the contaminating fluid (DG density): SIDPP - SICP = HG/10 (D-DG) DG = D - (SICP-SIDPP) x 10/HG

If If If

DG < 0,3 kg/l ===> gas DG < 0,7 kg/l ===> mixture DG > 0,7 kg/l ===> liquid

The contaminating fluid height can be determined by the increase in volume. HG= increase in volume/well annulus capacity ___________________________________________________________________________________ Eni Corporate University

77

WELL CONTROL _______________________________________________________________________________________________________

Determination of stabilised pressures Determining the moment of stabilisation can sometimes be difficult because of the migration of gas influx towards the surface, which induces a expansion and a subsequent pressure increase, constant but more gradual, rather than a pressure stabilisation.

In this case it is impossible to establish a true stabilisation point because the time lapse (A-B) which represents the stabilisation period tends to confuse with the time lapse (B-C) which represents the pressure increase due to the rising of the gas and to the subsequent expansion. When the exact determination of the stabilisation point is difficult, there are two possible strategies: Extend the observation time: with frequent pressure readings, stopping when the pressure increase tends to stabilise Interpolate the recorded values: - paired values are determined " observation time T - SIDPP", recorded with maximum accuracy, which allow to calculate the stabilised pressure values. - the straight line joining the SIDPP points (ordinate) and the SIDPP/T (abscissa) is traced . The intersection of the line with the pressure axis defines the stabilised SIDPP value.

As a general rule, a shut- in time of 10-20 minutes is enough to obtain the stabilised pressures. 78

_______________________________________________________________________________________ Eni Corporate University

Shut-in procedures _______________________________________________________________________________________________________

Particular situations The pressure reading at the drill pipes may be impossible because of the presence of a check valve which hinders the registration of the pressure value on the gauge. In this case, to determine the SIDPP value, the following procedure should be adopted: - start a slow circulation until the check valve opens. - the SIDPP value given on the gauge represents the stabilisation value.

Note :

Any increase in the SICP value must be avoided and it must be kept under observation during the procedure. Its increase means that the pressure induced by pumping through the drill pipes was too high and that it transferred into the casing (circulation with a shut-in well).

Anomalous situations related to stabilised pressures The readings of the stabilised pressure values delineate the following situations: 1)

0 0

. the penetrated fluid has the same density as the mud . the influx height is negligible . the fluid has entered into the pipes as well as into the casing, with the same height . influx due to swabbing penetrated under the bit

3)

0 =SIDPP < SICP

. this situation only occurs in presence of an influx, or it may be due to an excessive weight loss of the mud in the annulus caused by the drilling gas. This situation can occur when there is a check valve on the drilling string.

4)

0 < SICP