1 Well Control Principles 2 Primary Well Control Secondary Well Control Tertiary Well Control...

1

Well Control

Principles

2

• Primary Well Control

• Secondary Well Control

• Tertiary Well Control

• Hydrostatic Pressure

• Formation Pressure

• Porosity And Permeability

• Kill Mud Density

• Indications of Increasing Formation Pressure

Well Control Principles

3

The function of Well Control can be subdivided into 3 main categories:

• Primary Well Control: is the use of the fluid to prevent the influx of formation fluid into the well bore.

• Secondary Well Control: is the use of the BOP to control the well if Primary WC can not be maintained.

• Tertiary Well Control: squeeze back, cement ...

Well Control Principles

4

when Hydrostatic Pressure = Formation PressureThe Well is Balanced:

5

The Well is Under Balanced: when Hydrostatic Pressure < Formation Pressure

6

The Well is Over Balanced:

when Hydrostatic Pressure > Formation Pressure

7

Because the pressure is measured in psi and depth is measured in feet, it is convenient to convert Mud Weight

from ppg to a pressure gradient in psi/ft.

The conversion factor is 0.052

Fluid Density (ppg) x 0.052 = Pressure gradient (psi/ft)

Hydrostatic Pressure is the pressure exerted by a column of fluid at rest, and is calculated by multiplying the gradient of the fluid by the True Vertical Depth at which the pressure is

being measured:

Fluid gradient (psi/ft) x TVD = Hyd. Pressure(psi)

Hydrostatic Pressure

8

You have to consider the vertical height or depth of the fluid column, the shape of the hole doesn’t matter.

T V D

9

Normal formation pressure is equal to the hydrostatic pressure of the water occupying the pore spaces from the surface to the subsurface formation.

Native fluid is mainly dependent on its salinity and is often considered to be:

0.465 psi/ft

Normal Formation Pressure

10

Abnormal formation pressures are any formation pressures that are greater than the hydrostatic pressure of the water occupying the pore spaces.

Commonly caused by the under-compaction of shale’s, clay-stone or faulting...

Abnormal Formation Pressure

11

Subnormal Pressure: is defined as any formation pressure that is less than “normal” pressure.

It can be due to reservoir depletion,fault …

Transition Zone: is the formation in which the pressure gradient begins to change from a normal gradient to a subnormal gradient or, more usually, to an abnormal gradient.

12

ENCLOSED SAND LENS WITH FORMATION FLUID

UNCONSOLIDATED

SHALE-DENSITY DECREASES WITH DEPTH-WATER ENCLOSED

SAND WITH COMMUNICATION TO SURFACE

SHALE-DENSITY INCREASES WITH DEPTH - WATER ESCAPES

UNDERCOMPACTED SHALES / SAND.

13

GAS CAP

NORMAL FORMATIONPRESSURE ABOVE CAPROCK =0.465 PSI/FT

Pf

Pabnormal = Pf-Pg

Pg

GAS PRESSUREGRADIENT = 0.1 PSI/FT

COMMUNICATION BETWEEN FLUID AND GAS

Ph

14

SURCHARGED FORMATIONS

15

Pf

FAULT ZONE

NATURALLY SURCHARGED FORMATIONS

Pf

16

POROUS SANDSTONEBELOW CAP ROCK

HYDROSTATICPRESSUREFROMFORMATIONWATERCOLUMN

LAKE

ARTESIAN WELL

NORMAL FORMATIONPRESSURE AT THE WELLUNTILL BELOW THE CAP

ROCK

17

Pf

Pf

Pf

H1

H2

H3

SURFACE EROSIONENCLOSED FORMATION

LEVEL CHANGE

18

The essential properties of reservoir rocks are: - Their porosity and permeability.

The porosity provides the storage space for fluids and gases and isthe ratio of the pore spaces in the rock to the bulk volume of the rock.This is expressed as a percentage. Reservoir rocks commonly haveporosity’s ranging from 5% to 30%.

Formation permeability is a measure of how easy the fluid will flowthrough the rock. Permeability is expressed in Darcys, from a fewmilliDarcys to several Darcys.

These properties will determine how much and how quick a kick will enter into the well. Kicks will enter a wellbore faster from rocks having high permeability.

Porosity & Permeability

19

Tiny openings in rock are pores Porosity

Pores are connected for the Permeability

20

When the well is shut in, Formation Pressure can be found with the following formula:

SIDPP + Hydrostatic pressure = Formation Pressure

SICP + Influx Hyd + Mud Hyd = Formation Pressure

Formation Pressure

Formation Pressure

SIDPP

+

Mud Hydrostatic

=

SICP

+

Mud Hydrostatic

+

Influx Hydrostatic

=

21

KICK INDICATORS

22

POSITIVE KICK SIGNS

Positive Indications of a kick:

- Flow from Well (pumps off)

- Increase in Flow from Well (pumps on)

- Pit Volume Gain

23

KICKS WHILE TRIPPING

Incorrect Fill or Return Volumes

- Swabbing

- Surging

If any deviation, the FIRST action will be to install a fully open safety valve and make a Flow-Check.

Remember: It is possible that the well will not flow even if an influx has been swabbed in.

24

KICKS WHILE DRILLING

Early Warning SignsThat the well MIGHT be going under-balanced

25

Indications of Increasing Formation Pressure

• Increase in Drilling Rate

•Change in D - Exponent

• Change in Cutting size and shape

• Increase in Torque and Drag

•Chloride Trends

• Decrease in Shale Density

• Temperature Measurements

• Gas Cut Mud

• Connection Gas

26

While drilling normally pressured shale and assuming a fairly constant bit weight, RPM, and hydraulic program, a

normal decrease in penetration rate can be expected. When abnormal pressure is encountered, differential pressure and shale density are decreased causing a

gradual increase in penetration rate.

ROP

Depth

Increase in Drilling Rate:

27

Increase in torque and drag often occurs when drilling under balanced through some shale intervals.

There is a build up of cuttings in the annulus and this may be a sign that pore pressure is increasing.

Torque

Depth

Increase in Torque and Drag

28

“d” is an indication of drill ability and ROP, RPM, WOB, bit size are used to calculate its value.

Trends of “d” normally increase with depth, but in transition zones, it may decrease with lower than expected

value.

“d”

Depth

Change in “d” Exponent:

29

Normally pressured shale: cuttings are small with rounded edges, generally flat.

Abnormally pressured shale: cutting are long and splintery with angular edges.

As differential between the pore pressure and bottom pressure is reduced, the cuttings have a tendency to “explode” of bottom.

Change in cutting size and shape

30

The chloride content of the mud filtrate can be monitored both going into and coming out of the hole.

A comparison of chloride trends can provide a warning or confirmation signal of increasing pore pressure.

Chloride

Depth

Chloride Trends:

31

Shale density normally increases with depth but decreases as abnormal pressure zones are drilled.

When first deposited, shale has a high porosity. During normal compaction, a gradual reduction in porosity occurs

with an increase of the overlaying sediments.

Shale

Density

Depth

Decrease in Shale Density:

32

The temperature gradient in abnormally pressured formations is generally higher than normal.

Temp.

Depth

Temperature Measurements:

33

The presence of gas cut mud does not indicate that the well is kicking ( gas may have been entrained in the cutting ). However, the presence of gas cut

mud must be treated as an early warning sign of a potential kick.

- Gas cut mud only slightly reduces mud column pressure, when it is close to surface.

- Drilled cuttings from which the gas comes may compensate for the decrease.

Gas Cut Mud

34

Connection gas are detected at the surface as a distinct increase above the background gas, as bottom up is circulated after a connection.

Connection gases may indicate a condition of near balance.

If connection gas is present, limiting its volume by controlling the drilling rate should be considered.

Connection Gas

35

SYSTEM PRESSURE LOSSES

36

Objectives

• Identify the different pressures losses in the system

• Identify which one influence bottom hole pressure

• Convert this pressure to an equivalent mud weight

37

Mud System Pressure Losses

• Pumping through a pipe with a mud pump at 80 spm, with gauges mounted on the discharge of the pump and at the end of the pipe.

• The gauge on the pump reads 100 psi.

• The gauge on the end of the pipe reads 0 psi.

• It can be assumed from this information that the 100 psi drop in pressure through the pipe is the result of friction losses in the pipe as the fluid is pumped through it.

100 psi100 psi

100 psi100 psi

0 psi0 psi

80 SPM80 SPM

38

500 psi500 psi

100 psi100 psi

400 psi400 psi

0 psi0 psi

400 psi400 psi


80 SPM80 SPM

39

1000 psi1000 psi

100 psi100 psi

900 psi900 psi

500 psi500 psi400 psi400 psi

0 psi0 psi

500 psi500 psi


80 SPM80 SPM

40

2300 psi2300 psi

100 psi100 psi

2200 psi2200 psi


1300 psi1300 psi

500 psi500 psi

1300 psi1300 psi


0 psi0 psi

80 SPM80 SPM

41

2600 psi2600 psi

100 psi100 psi

2500 psi2500 psi

2100 psi2100 psi400 p

si400 p

si

1600 psi1600 psi

500 psi

500 psi

1300 psi1300 psi

0 psi0 psi

300 psi300 psi

300

psi

300

psi


Annular

Pressure

Losses

80 SPM80 SPM

42

APL EXAMPLE• A well has been drilled to

10,000 ft.

• The mud weight is 10 ppg.

• To find our Hydrostatic pressure we use the following formula;

• Mud Wt x 0.052 x TVD 10 x 0.052 x 10,000 = 5,200psi.

• The gauge on the drawing shows bottom hole hydrostatic pressure.

0 psi0 psi


0 psi0 psi

0 psi0 psi

5200 psi5200 psi

10,000 ft TVD10,000 ft TVD

MUD WT = 10 ppgMUD WT = 10 ppg


0 SPM0 SPM

43

APL EXAMPLE

• If we now start to circulate at 80 spm through our system with the same pressure losses as before.

• As you can see from this example the bottom hole pressure has increased by 300 psi.

• This increase is due to the Annular Pressure Losses (APL) acting down on the bottom of the well and is usually called “Bottom Hole Circulating Pressure” (BHCP)

2600 psi2600 psi

100 psi100 psi

2500 psi2500 psi

2100 psi2100 psi

400 psi400 psi

1600 psi1600 psi

500 psi500 psi

1300 psi1300 psi

0 psi0 psi

5500 psi5500 psi

300

psi

300

psi

10,000 ft TVD10,000 ft TVD



80 SPM80 SPM

44

Equivalent Circulating Density

The APL while circulating has the same effect on bottom hole pressure as increasing the mud

weight.

This theoretical increase in mud weight is called the Equivalent Circulating Density or Equivalent

Mud Weight.

It can be calculated by using the following formula:

_____APL(psi) __ + Original Mud Weight

TVD x 0.052

45

•Annular Pressure Losses are the pressure losses caused by the flow of fluid up the annulus and are the only losses in the system that affect BHP.

•Equivalent Circulating Density is the effective density at any depth created by the sum of the total hydrostatic plus the APL.

Summary:

46

300 psi300 psi

600 psi600 psi

800 psi800 psi

1200 psi1200 psi

450

psi

450

psi


MD = 9,550 ftMD = 9,550 ft

TVD = 8,000 ftTVD = 8,000 ft

Exercise- Pressure Gradient?

- Hydrostatic Pressure?

- Pump Pressure @ 40 spm?

- A P L?

- ECD at 40 SPM?

40 SPM40 SPM

47

EFFECTS ON PRESSURES

48

MUD WEIGHT CHANGE

• A well is being drilled using 10 ppg mud. At 80 spm the total circulating system pressure losses are 2600 psi.

• It is decided to increase the mud weight to 11 ppg.

2600 psi2600 psi

Mud wt 10 ppg

80 spm

49

It is a good drilling practice to calculate the new circulating pressure before changing the mud weight.

The way we calculate this change in pressure is to use the following formula;

New Mud ppg x Old psi.

Old Mud ppg

11 ppg x 2600 = 2860psi

10 ppg

The new pump pressure would be approximately 2860 psi.

2860 psi2860 psi

Mud wt 11 ppg

80 spm

MUD WEIGHT CHANGE

50

Final Circulating Pressure

• The formula that was just used to calculate the pressure change due to a change in mud weight, is also the formula used to calculate the Final Circulating Pressure.

Kill Mud wt x Slow circulating rate press .

Old Mud wt

51

PUMP STROKE CHANGE

• A well is being drilled using 10 ppg mud. At 80 spm the total circulating system pressure losses are 2600 psi.

• It is decided to increase the pump speed from 80 spm to 100 spm.

2600 psi2600 psi

Mud wt 10 ppg

80 spm

52

• It is a good drilling practice to calculate the new circulating pressure before changing the pump speed.

• The way we calculate this change in pressure is to use the following formula;

• New SPM 2 Old psi x Old SPM

• 2600 x 100 spm 2 80 spm = 4063 psi

• The new pump pressure would be approximately 4063 psi.

4063 psi4063 psi

Mud wt 10 ppg

100 spm

PUMP STROKE CHANGE

53

Preparation

and

Prevention

54

• Barite and Mud chemical stocks

• Equipment line up for shut-in

• Slow circulating rates

• M A A S P

• Well Control Drills

• Flow Checks

• Safety Valves and Float Valves

Preparation and Prevention

55

FLOWPATH

LINE UP FORHARD SHUT IN

56

FLOWPATH

HARD SHUT INPick off bottom and position string

Stop pumps & Rotation

Close BOP (Ram or Annular)

Open hydraulic side outlet valve

Observe pressure 1

1

2

2

3

3

4

4

5

5

57

LINE UP FORSOFT SHUT IN

FLOWPATH

58

SOFT SHUT INPick off bottom and position string

Stop pumps & Rotation

Open hydraulic side outlet valve

Close BOP (Ram or Annular)

Close remote hydraulic choke

Observe pressure

1

1

2

2

3

3

4

4

5

5

6

6

FLOWPATH

59

• A Slow Circulating Rate ( SCR) is the reduced circulating pump rate that is used when circulating out a kick.

• It is called Dynamic Pressure Losses ( PL ) on the kick sheet

Slow Circulating Rate

60

Well Control Operations are conducted at reduced circulating rates in order to:

• Minimise Excess of annulus pressure• Allows for more controlled choke adjustments• Allows for the weighting up and degassing of

the mud and disposal of the influx• Reduce the chance of choke erosion• Reduce risk of over pressuring system if

plugging occurs


61

SCR’s pressure for each pump will be taken:

• If practical, at the beginning of every tour• Any time the mud properties are changed• When a bit nozzle is changed.• When the BHA is changed.• As soon as possible after bottoms-up from

any trip• At least every 1000 feet (305m) of new hole


62

• A minimum of 2 (two) circulating rates should be obtained for all pumps.

• The pressure must be recorded using the gauges that will be used during well kill operations

• The SCR pressure will be recorded on the IADC report


63

Formation Strength Test or LOT

A leak off test (LOT) determines the pressure at which the formation begins to take fluid.

This test is conducted after drilling out about 10 to 15 ft of new hole below the shoe.

Such a test will establish the strength of the formation and the integrity of the cement job at the shoe.

The test pressure should not exceed 70% of the minimum yield of the weakest casing.

64

Use a high pressure, low volume pump (0.25 - 0.5 bbl/min.) such as a cement pump or a test pump using intermittent or continuous method of pumping. Rig pumps are not suitable to perform leak off tests.

The objective of the above test is not to fracture the formation, but rather to identify the “formation intake pressure”.This “intake pressure” is identified as that point where a deviation occurs between the trends of the final pump pressure curve and the static pressure curve. Once the formation intake pressure has been reached, further pumping should be avoided.

L O T

65

+ Hydrostatic Pressure

=

Pressure at Shoe

Surface Casing

Pressure

The total pressure applied at the shoe is the sum of the surface pressure from the pump and the hydrostatic

pressure for the shoe depth.

This total pressure is applied to the formation.

L O T

66

3,000’

720 psi

9.6 ppg

+

1498 psi

2218 psi

720 psi

This total pressure is applied to the formation.

L O T

67

The Maximum Available Fluid Density (MAMW).

This is the total pressure, represented as fluid density,

above which leak off or formation damage may occurs with no pressure on surface.

2218 psi

0 psi

3,000’

MAMW= 2218

3000 x 0.052

MAMW = 14.2 ppg

M A M W

68

2218 psi

0 psi

3,000’

The fracture gradient of the formation will be:

Fracture gradient = MAMW x 0.052

Fracture Gradient = 14.2 x 0.052

= 0.7384 psi/ft

therefore:

MAMW = Fracture Gradient / 0.052

Fracture Gradient

69

MAASP is defined as the surface pressure which, when added to the hydrostatic pressure of the existing mud column, results in formation breakdown at the weakest point in the well.

This value is based on the Leak Off Test data.

Maximum Allowable Annular Surface pressure

M A A S P

70

On Kill Sheet

Calculate current MAASP and insert here

Write mud weight used for the test

Calculate maximum allow mudweight and Insert here

Write leak off test pressure here

71

Drills

• Pit drill

• Trip drill

• Abandonement drill

• Strip drill

72

Actions

Upon

Taking a Kick

73

• Causes for the Loss of Primary Well Control

• Kick Size and Severity

• Kick Detection

• Recording Pressures

• Drilling With Oil Base Mud

• Hard Shut-in

• Soft Shut-in

• Height and Gradient of a Kick

74

Causes for the loss of Primary Well Control

• Failure to Fill The Hole Properly While Tripping

• Swabbing / Surging

•High pulling speed

•Mud properties

•Tight annulus clearance

•Well Geometry

•Formation Properties

• Lost Circulation

• Insufficient Drilling Fluid Density

75

Kick Size and SeverityMinimizing kick size is fundamental for the safety of a Well Control operation.Smaller Kicks: Provide lower choke or annulus pressure both upon initial closure and later when the kick is circulated to the choke.

Controllable Parameters: You can influence on:

• Degree of underbalance Mud Weight

• Length of reservoir exposed ROP + Kick detection time

• Time well remains underbalanced Kick detection + shut-in time

• Wellbore diameter Hole size

Non-controllable Parameters

• Formation permeability and type of influx

76

While Drilling:

• Drilling breaks: They will be flow checked. Circulating B/up is advisable if F/C is negative. Tool pusher must be informed for all.

• Increase in flow rate: First positive indicator.

• Increase in pit volume: Positive indicator. Anyone influencing the active system must communicate with the Driller.

• Variation in Pump speed and Pressure: (“U-tube”)

• Well flowing during a Connection: ECD to ESD

• Change of drilling fluid properties: Gas cut or fluid contaminated.

While Tripping:

• Improper fill-up: swabbing or surging

Kick Detection

77

• Stop rotation

• Pick up the drill string to shut-in position (subsea to hang off position)

• Stop the pump

• Flow check

If the well flows• Close BOP

• Open remote control choke line valve

• Notify Tool Pusher and OIM

• Record time, SIDPP, SICP and pit gain

Shut- in Procedure: HARD SHUT-IN

78

•Stop rotation

• Pick up the drill string to shut-in position (Subsea to hang off position)

•Stop the pump

• Flow check

If the well flows• Open remote control choke line valve

• Close BOP

• Close choke

• Notify Tool Pusher

• Record time, SIDPP, SICP and pit gain

Shut- in Procedure: SOFT SHUT-IN

79

Close-in Methods specified byAmerican Petroleum Institute

• Soft close-in procedure• For a soft close-in, a choke is left open

at all times other than during a well control operation. The choke line valves are aligned such that a flow path is open through the choking system, with the exception of one choke line valve located near the blow out preventer. When the soft close-in procedure is selected for closing in a well the:

• 1 choke line valve is opened.• 2 Blow out preventer is closed.• 3 Choke is closed.• This procedure allows the choke to be

closed in such a manner to permit sensitive control and monitoring of casing pressure buildup during closure.

• Hard close-in procedure• For a hard close-in, the chokes remain

closed at all times other than during a well control operation. The choke line valves are aligned such that a flow path is open through the choking system with the exemption of the choke(s) itself and one choke line valve located near the blow out preventer stack. When the hard close-in procedure is selected for closing in a well, the blow out preventer is closed. If the casing pressure cannot be measured at the well head, the choke line valve is opened with the choke or adjacent high pressure valve remaining closed so that pressure can be measured at the choke manifold. This procedure allows the well to be closed in the shortest possible time, thereby minimising the amount of additional influx of kicking fluid to enter the well bore.

80

Surface Pressure After Shut-in

81

OIL BASE MUD

82

Drilling with OBM

83

Gas Influx in WBM or in OBM

Water Base Mud

• Easier to detect

• Higher migration rate

• Gas stay as a separate phase

• On bottom bigger kick size

• Higher casing pressure

• Expansion:

- Slow first then Fast

Oil Base Mud

• More difficult to detect

• Lower migration rate

• Gas go into solution

• On bottom smaller kick size

• Smaller casing pressure

• Expansion:

- none first then very fast at the bubble point

84

Height and Gradient of a Kick

85

Well Kill

Techniques

86

• Driller’s Method

• Wait and Weight Method

•Volumetric Method

87

Well Kill Techniques

88

Driller’s Method : 1 st Circulation

The original mud weight is used to circulate the influx

- Reset the stroke counter.

- Bring the pump up to kill speed while holding the casing pressure constant.

- Maintain DP pressure constant until the influx is circulated out from the well

BHP

89


The maximum shoe pressure is when the top of the influx reaches the shoe

90


When the influx is passing the casing shoe, the shoe pressure will decrease.

91


When the influx is above the casing shoe, the shoe pressure will remain constant.

92


- Surface casing pressure is increasing as the influx is circulated up the well.

- Pit volume is raising.

93


- The maximum surface casing pressure is reached when the top of the influx is at surface.

- It will be the maximum increase in pit level.

94


- As the influx is passing through the choke, the surface casing pressure will decrease.

- The pit volume will decrease.

95


If all the influx is successfully circulated from the well and the pump is stopped,

SIDPP = SICP

96

Driller’s Method : 2 nd Circulation

- Line up the kill mud.

- Reset the stroke counter.

- Bring the pump up to kill speed while holding the casing pressure constant.

- Reset the stroke counter after pumping the surface line volume.

- Keep the casing pressure constant until KMW reach the bit.

( Or follow the calculated DP pressure drop schedule from ICP to FCP.)

Pit volume has increased due to the weighting material added in the system.

97

Driller’s Method : 2 nd Circulation

When kill mud enters the annulus, maintain FCP constant until kill mud is at surface.

98

Driller’s

Method

Driller’s

Method

Drill Pipe

Casing

First Circulation

99

Driller’s

Method

Driller’s

Method

Drill Pipe

Casing

Second Circulation

100

Driller’s MethodAdvantages:

- Can start circulating right away

- Able to remove influx even if not enough barite on board

- Less chance of gas migration

- Less calculation

Disadvantages:

- Higher surface pressure

- In certain situation, higher shoe pressure

- Two circulation, more time through the choke

101

Wait and Weight-The kill mud weight is used to circulate the influx

-Reset the stroke counter

- Bring the pump up to kill speed while Holding the casing pressure constant.

- Reset the stroke counter after pumping the surface line volume.

-Pump kill mud from surface to bit while following a calculated DP pressure drop schedule.

BHP

102

When kill mud enters the annulus, maintain FCP constant until kill mud is at surface.

Wait and Weight

103

Drill Pipe

Casing

Wait&

Weight

Wait&

Weight

One Circulation Only

104

Wait & Weight MethodAdvantages:

- Can generate lower pressure on formation near the casing shoe

- In most situation generate less pressure on surface equipment

- With a long open hole, less chance to induce losses

- One circulation, less time spent circulating through the choke

Disadvantages:

- Longer waiting time prior to circulate the influx

- Cutting could settle down and plug the annulus

- Gas migration might become a problem

- Need to have enough barite to increase the mud weight

- More Calculations

105

Drillers MethodGas at Casing Shoe

h'i

hm

W & W MethodGas at Casing Shoe,kill mud in drill string

h'i

hm

Differences between W&W and Driller’s methods

106

Drillers MethodGas at Casing Shoe

h'i

hm

W & W Method Gas at Casing Shoe,Kill mud in annulus

h''i

hm

hkm

Differences between W&W and Driller’s methods

107

• Free gas expansion

• No gas expansion

• Volume to bleed off to maintain BHP constant

Gas Behavior

108

Gas may be swabbed into a well and remain at TD. The influx will expand as it moves up the annulus when circulation is started. The amount of expansion can easily be calculated. If undetected, free gas expansion can cause a serious well

control problem.

Free Gas Expansion

109

DPVg

D=

10,0

00ft

CST

10,0005,000

15,000

Gm = 0.5 psi/ft

A column of 10,000ft of mud, Gm=0.5psi/ft compresses one barrel of gas at TD.

The pressure in the gas is;10,000 x 0.5 = 5,000 psi

Multiply P x Vg to find the constant.

Gas

Free Gas Expansion

110

D

PVg

D=

5,00

0ft

PVg

10,0005,000

15,000

Gm = 0.5 psi/ft

The gas has risen so that the top of the bubble is at 5,000ft from the surface.


Using the constant, the volume of gas is found: 5,000 / 2,500 = 2 barrels

5,0002,500

25,000

Free Gas Expansion

111

DPVg

PVg

10,0005,000

15,000

The top of the bubble is at 2,500ft from the surface.


The volume of gas is found: 5,000 / 1,250 = 4 barrels

5,0002,500

25,000

2,5001,250

45,000

D=

2,50

0ft

Free Gas Expansion

Gm = 0.5 psi/ft

112

At 1,250ft from the surface.

Pressure;1,250 x 0.5 = 625 psi

Volume of gas; 5,000 / 625 = 8 barrels

D=

1,25

0ft

DPVg

PVg

10,0005,000

15,000

5,0002,500

25,000

2,5001,250

45,000

1,250625

85,000

Free Gas Expansion

Gm = 0.5 psi/ft

113

DPVg

PVg

10,0005,000

15,000

5,0002,500

25,000

2,5001,250

45,000

1,250625

85,000

014.7341

5,000

Free Gas Expansion

Gm = 0.5 psi/ft

114

0 ft

2,500 ft

5,000 ft

7,500 ft

10,000 ft

0 psi

5,200 psi

1 bbls

1 bbl gain

Gm = 0.52 psi/ft

No Gas Expansion

115

0 ft

2,500 ft

5,000 ft

7,500 ft

10,000 ft

0 psi 1,300 psi

6,500 psi5,200 psi

1 bbls

1 bbls

1 bbl gain 1 bbl gain

Gm = 0.52 psi/ft

No Gas Expansion

116

0 ft

2,500 ft

5,000 ft

7,500 ft

10,000 ft

0 psi 1,300 psi 2,600 psi

7,800 psi6,500 psi5,200 psi

1 bbls

1 bbls

1 bbls

1 bbl gain 1 bbl gain 1 bbl gain

Gm = 0.52 psi/ft

No Gas Expansion

117

0 ft

2,500 ft

5,000 ft

7,500 ft

10,000 ft

0 psi 1,300 psi 2,600 psi 3,900 psi

7,800 psi 9,100 psi6,500 psi5,200 psi

1 bbls

1 bbls

1 bbls

1 bbls

1 bbl gain 1 bbl gain 1 bbl gain 1 bbl gain

Gm = 0.52 psi/ft

No Gas Expansion

118

0 ft

2,500 ft

5,000 ft

7,500 ft

10,000 ft

0 psi 1,300 psi 2,600 psi 3,900 psi 5,200 psi

7,800 psi 9,100 psi 10,400 psi6,500 psi5,200 psi

1 bbls

1 bbls

1 bbls

1 bbls

1 bbls

1 bbl gain 1 bbl gain 1 bbl gain 1 bbl gain 1 bbl gain

Gm = 0.52 psi/ft

No Gas Expansion

119

0 ft

2,500 ft

5,000 ft

7,500 ft

10,000 ft

500 psi 1800 psi 500 psi

5,700 psi7000 psi5,700 psi

1 bbls

1bbls1.3bbls

1 bbl gain 1 bbl gain 1.3 bbl gain

Volume to bleed off to keep BHP constant

2500 x .52 = 1300 psi

5700 psi 4400 psi

P1V1 = P2V2

V2 = 5700 x 1 / 4400

V2 = 1.29 bbls

Gm = 0.52 psi/ft

120

0 ft

2,500 ft

5,000 ft

7,500 ft

10,000 ft

500 psi 1800 psi 500 psi

5,700 psi7,000 psi5,700 psi

1.3 bbls

1.3bbls

1.84bbls

1.3 bbl gain 1.3 bbl gain 1.84 bbl gain

5000 x .52 = 2600 psi

4400 psi

3100 psi

P1V1 = P3V3

V3 = 5700 x 1 / 3100

V3 = 1.84 bbls

Gm = 0.52 psi/ft


121

0 ft

2,500 ft

5,000 ft

7,500 ft

10,000 ft

500 psi 1800 psi 500 psi

5,700 psi7,000 psi5,700 psi

1.8 bbls

1.8bbls 3.16bbls


7500 x .52 = 3900 psi

3100 psi 1800 psi

P1V1 = P4V4

V4 = 5700 x 1 / 1800

V4 = 3.16 bbls

Gm = 0.52 psi/ft


122

0 ft

2,500 ft

5,000 ft

7,500 ft

10,000 ft

500 psi 1800 psi 500 psi

5,700 psi7,000 psi5,700 psi

3.16 bbls

3.16 bbls 11.4bbls


10000 x .52 = 5200 psi

1800 psi 500 psi

P1V1 = P5V5

V5 = 5700 x 1 / 500

V5 = 11.4 bbls

Gm = 0.52 psi/ft


123

WELL # 1HOLE SIZEHOLE DEPTH TVD/MDCASING 9-5/8” TVD/MDDRILL PIPE CAP.HEAVY WALL DRILL PIPECAPACITYDRILL COLLARS 6-1/4”CAPACITYDRILLING FLUID DENSITYCAPACITY OPEN HOLE/COLLARSCAPACITY OPEN HOLE/DRILL PIPE-HWDPCAPACITY CASING/DRILL PIPEFRACTURE FLUID DENSITYSIDPPSICPPUMP DISPLACEMENTRRCP 30 SPMPIT GAIN

8-1/2 INCH11536 FEET9875 FEET0.01741 BBL/FEET600 FEET0.00874 BBL/FEET880 FEET0.00492 BBL/FEET14.0 PPG0.03221 BBL/FEET0.04470 BBL/FEET0.04891 BBL/FEET16.9 PPG530 PSI700 PSI0.1019 BBL/STRK650 PSI10.0 BBL

124

DRILLERS METHOD1st CIRCULATION

0

O C

Ph= 8398 psi

Pf= 8928 psi

530 700

1489MAASP

7189

0

7889

SHUTTINGSHUTTINGININ

WELLWELL

DP CSG

125


O C

Pf= 8928 psi

1489MAASP

7889

700

30

22

1180REACHINGREACHING

ICPICP

KEEP CONSTANTCASING PRESSURE

WHILE BRINGINGPUMPS UP

PUMPS UP ANDPRESSURE STABILISED

KEEP CONSTANTDRILL PIPE PRESSURE

DP CSG

BHP= 8928 PSI

126


O C

30

1180

Pf= 8928 psi

1489310

740

MAASP

7929

DP CSG

GAS IN OPEN HOLEGAS IN OPEN HOLE

CONSTANTDRILL PIPE PRESSURE

GAS EXPANDING

CASING PRESSUREINCREASE

SHOE PRESSUREINCREASE

MAASP CONSTANTBHP= 8928 PSI

127


O C

1180

30

MAASP

1489470

Pf= 8928 psi

BHP= 8928 PSI

775

7964

GAS REACH SHOEGAS REACH SHOE


GAS EXPANDING


SHOE PRESSUREINCREASE TO MAX

MAASP CONSTANT

DP CSG

128


O C

1180

30

BHP= 8928 PSI

Pf= 8928 psi

MAASP620

785

7718

1685GAS MOVES INSIDEGAS MOVES INSIDECASINGCASING


GAS EXPANDING


SHOE PRESSUREDECREASE

MAASP INCREASING

DP CSG

129


O C

1180

30

2300

Pf= 8928 psi

BHP= 8928 PSI

1120

7718

2020MAASP

GAS MOVING INSIDEGAS MOVING INSIDECASINGCASING


GAS EXPANDING


SHOE PRESSURECONSTANT

MAASP INCREASING

DP CSG

130


O C

1180

30

4800

BHP= 8928 PSI

Pf= 8928 psi

MAASP

1580

7718

2480GAS REACH CHOKEGAS REACH CHOKE


GAS EXPANDING

CASING PRESSUREINCREASE TO MAX


MAASPINCREASE TO MAX

DP CSG

131


O C

1180

30

5400

BHP= 8928 PSI

Pf= 8928 psi

530

7718

1489GAS OUT OF WELLGAS OUT OF WELL


CASING PRESSUREDECREASING TO SIDPP


MAASP DECREASINGTO ORIGINAL VALUE

MAASP

DP CSG

132

DRILLERS METHOD2nd CIRCULATION

O C

30

1180

5400

530

1489

7718

BHP= 8928 PSI

Pf= 8928 psi

START PUMPINGSTART PUMPINGKILL MUD 14.9 PPGKILL MUD 14.9 PPG

CASING PRESSURECONSTANT


MAASP CONSTANT

MAASP

DP CSG

133


O C

530

1489

7718

BHP= 8928 PSI

Pf= 8928 psi

30

6306

936

KILL FLUID INSIDEKILL FLUID INSIDEDRILL PIPEDRILL PIPE

CASING PRESSURECONSTANT

DRILL PIPE PRESSUREDECREASING


MAASP CONSTANT

MAASP

DP CSG

134


O C

BHP= 8928 PSI

Pf= 8928 psi

1489

7718

530

30

7212

692

KILL MUD REACHKILL MUD REACHBITBIT

CONSTANT CASINGPRESSURE

DRILL PIPE PRESSUREDECREASING TO FCP


MAASP CONSTANT

MAASP

DP CSG

135


O C

BHP= 8928 PSI

Pf= 8928 psi

692

30

78321489

469

7657

MAASPKILL MUD REACHKILL MUD REACH

SHOESHOE

DRILL PIPE PRESSURECONSTANT

CASING PRESSUREDECREASING

SHOE PRESSUREDECREASING

MAASP CONSTANT

DP CSG

136


O C

MAASP

DP CSG

692

30

10202

BHP= 8928 PSI

Pf= 8928 psi

KILL MUD INSIDEKILL MUD INSIDECASINGCASING




MAASP DECREASING

233

7657

1253

137


O C

MAASP

DP CSG

692

30

12600

BHP= 8928 PSI

Pf= 8928 psi

0

7657

1020KILL MUD ATKILL MUD ATSURFACESURFACE


CASING PRESSUREDECREASING TO ZERO


MAASP DECREASINGTO NEW MAASP w/KMW

138

WELL # 1

HOLE SIZEHOLE DEPTH TVD/MDCASING 9-5/8” TVD/MDDRILL PIPE CAP.HEAVY WALL DRILL PIPECAPACITYDRILL COLLARS 6-1/4”CAPACITYDRILLING FLUID DENSITYCAPACITY OPEN HOLE/COLLARSCAPACITY OPEN HOLE/DRILL PIPE-HWDPCAPACITY CASING/DRILL PIPEFRACTURE FLUID DENSITYSIDPPSICPPUMP DISPLACEMENTRRCP 30 SPMPIT GAIN


139

WAIT & WEIGHT METHOD

0

O C

Ph= 8398 psi

Pf= 8928 psi

530 700

1489MAASP

7189

0

7889

SHUTTINGSHUTTINGININ

WELLWELL

MIXING KILL MUD14.9 PPG

DP CSG

140

O C

Pf= 8928 psi

1489MAASP

7889

700

30

22

1180

REACHINGREACHINGICPICP

KEEP CONSTANTCASING PRESSURE

WHILE BRINGINGPUMPS UP

PUMPS UP ANDPRESSURE STABILISED

KEEP DRILL PIPEPRESSURE ON

SCHEDULE

DP CSG

BHP= 8928 PSI


141

O C

MAASP

DP CSG


BHP= 8928 PSI

Pf= 8928 psi

30

310

1097 740

7929

1489GAS IN OPEN HOLEGAS IN OPEN HOLE


CASING PRESSUREINCREASING

GAS EXPANDING

SHOE PRESSUREINCREASING

MAASP CONSTANT

142

O C

MAASP

DP CSG


30

BHP= 8928 PSI

Pf= 8928 psi

470

1053 775

7964

1489GAS REACH SHOEGAS REACH SHOE



GAS EXPANDING

SHOE PRESSUREINCREASE TO MAX

MAASP CONSTANT

143

O C

MAASP

DP CSG


30

BHP= 8928 PSI

Pf= 8928 psi

620

1013 785

7718

1685GAS MOVES INSIDEGAS MOVES INSIDECASINGCASING



GAS EXPANDING


MAASP INCREASING

144

O C

MAASP

DP CSG


30

BHP= 8928 PSI

Pf= 8928 psi

1812

692 1050

7718

1950KILL MUD AT BITKILL MUD AT BITGAS INSIDE CASINGGAS INSIDE CASING

DRILL PIPE PRESSUREDECREASE TO FCP


GAS EXPANDING


MAASP INCREASING

145

O C

MAASP

DP CSG


BHP= 8928 PSI

Pf= 8928 psi

30

2432

692 1080

7641

1980KILL MUD AT SHOEKILL MUD AT SHOEGAS INSIDE CASINGGAS INSIDE CASING



GAS EXPANDING


MAASP INCREASING

146

O C

MAASP

DP CSG


30

4800

BHP= 8928 PSI

Pf= 8928 psi

692 1278

7641

2178KILL MUD INSIDEKILL MUD INSIDECASINGCASING

GAS REACH CHOKEGAS REACH CHOKE



GAS EXPANDING


MAASP INCREASING

147

O C

MAASP

DP CSG


BHP= 8928 PSI

Pf= 8928 psi

30

5360

692 180

7641

1204KILL MUD INSIDEKILL MUD INSIDECASINGCASING

GAS OUT OF WELLGAS OUT OF WELL




MAASP DECREASING

148

O C

MAASP

DP CSG


30

7200

BHP= 8928 PSI

Pf= 8928 psi

692 0

7641

1027KILL MUD ATKILL MUD ATSURFACESURFACE


CASING PRESSUREDECREASING TO ZERO


MAASP DECREASINGTO NEW MMASP w/KMW

149

WELL # 1

HOLE SIZEHOLE DEPTH TVD/MDCASING 9-5/8” TVD/MDDRILL PIPE CAP.HEAVY WALL DRILL PIPECAPACITYDRILL COLLARS 6-1/4”CAPACITYDRILLING FLUID DENSITYCAPACITY OPEN HOLE/COLLARSCAPACITY OPEN HOLE/DRILL PIPE-HWDPCAPACITY CASING/DRILL PIPEFRACTURE FLUID DENSITYSIDPPSICPPUMP DISPLACEMENTRRCP 30 SPMPIT GAIN


150

VOLUMETRIC METHODVOLUMETRIC METHOD

MIGRATION DISTANCEMIGRATION DISTANCE

GMD = -------------------------GMD = -------------------------

MIGRATION DISTANCEMIGRATION DISTANCE

GMD = -------------------------GMD = -------------------------P2 - P1

MUD GRADIENT

MIGRATION RATE/HRSMIGRATION RATE/HRS

GMR = -------------------------GMR = -------------------------

MIGRATION RATE/HRSMIGRATION RATE/HRS

GMR = -------------------------GMR = -------------------------GMD x 60

T2 - T1

151


KEY POINT:

EVERY BARREL OF MUD IN THE WELLBORE REPRESENT A CERTAIN AMOUNT OF HYDROSTATIC PRESSURE

Ph Ph

152


CHOKE PRESSURECHOKE PRESSURE

SICP + SAFETY FACTOR + WORKING RANGESICP + SAFETY FACTOR + WORKING RANGE

PRESSURE/BARRELPRESSURE/BARREL

PSI/BBL = ----------------------------PSI/BBL = ----------------------------

14.88 = ----------------------------14.88 = ----------------------------

MUD GRADIENT

CAPACITY

14 x 0.052

0.04891

WORKING RANGEWORKING RANGE50 PSI50 PSI

VOLUME TO BLEED =--------------------VOLUME TO BLEED =--------------------

3.36 BBL =-----------------------------3.36 BBL =-----------------------------

W.R.

PSI/BBL

50

14.88

153

PA

10000 ft

12.5 ppg

300 psi

6500 psi

GAS

GMD = --------------------------

GMR = --------------------------

Where: GMD = Gas migration distanceMWG = Mud gradientP1 = Surface pressure at time T1

P2 = Surface pressure at time T2 GMR = Gas migration rate ( feet per hour)T1 = Time 1 (hour)T2 = Time 2 (hour)

P2 - P1

MWG

GMD

T2 - T1


154

PA

10000 ft

12.5 ppg

300 psi

6500 psi

GAS

GMD = --------------------------

GMR = --------------------------

Where: GMD = Gas migration distanceMWG = Mud gradientP1 = Surface pressure at time T1

P2 = Surface pressure at time T2 GMR = Gas migration rate ( feet per hour)T1 = Time 1 (hour)T2 = Time 2 (hour)

P2 - P1

MWG

GMD

T2 - T1


155

HALLIBURTON

BOP

PA

KILL LINE

GAS

PUMP

1

2

3

4

5


156

HALLIBURTON

BOP

PA

KILL LINE

GAS

SICP

P1

P1

P3

P3

P3

P3

P3

Vm

Vm

Vm

Vm

BLEED OFF LUBRICATE

GAS

GAS

GAS

GAS

GAS

1

2

3

4

5

6

1

2

3 4

5

6

BHP

Pa


157


BLEED OFF LUBRICATE

Gas bubble pressure

Bottom hole pressure

Annular pressure

Drill pipe pressure

TIME

PRESSURE

158

Bull heading

• Involves forcing formation fluids back into the formation using surface hydraulics

• Usually considered if: 1 Formation fluid cannot be safely handled on surface (eg with H2S)

2 If anticipated formation pressures exceed what can be safely handled

• Method usually employed as a last resort

159

Tertiary well control Methods

• Cement Plug

• Barite plug

• Gunk plug

160

Evaluation & Planning

•Drill a pilot hole

• Heavy mud in ready(1-2 ppg higher)

•Controlled ROP

•Use of Viscous pills instead of weighted pills

•High circulation rates

•Float in string

Shallow Gas

161

Diverting Shallow Gas

• Open vent line

• Close Diverter

• Switch suctions to heavy mud

• Increase pump speed to maximum

• Circulate heavy mud round

• Flow check• If still positive continue pumping.( if mud finished

continue with water)

INTERLOCKED

162

Well Control

Complications

163

Well Control Complications

164

WELL CONTROL COMPLICATIONS

165

Lost Circulation

• Formation breakdown

• Fractures and Fissures

• Bad cement

166

Loss Circulation

Categories:• Seepage losses (<2bbl/Hr)

• Partial losses (5-50 bbl/Hr)

• Severe losses (>50bbl/Hr)

• Complete losses (unable to maintain fluid level at surface with desired mud weight)

167

Hydrates

Hydrates

168

What are hydrates?

• Hydrates are a solid mixture of water and natural gas (commonly methane).

• Once formed, hydrates are similar to dirty ice .

Hydrates

169

Why are they important?

• Hydrates can cause severe problems by forming a plug in Well Control equipment, and may completely blocking flow path.

• One cubic foot of hydrate can contain as much as 170 cubic feet of gas.

• Hydrates could also form on the outside of the BOP stack in deepwater.

Hydrates

170

Where do they form?

• In deepwater Drilling

• High Wellhead Pressure

• Low Wellhead temperature

Hydrates

171

How to prevent hydrates?

• Good primary well control = no gas in well bore

• Composition of Drilling Fluid by using OBM or Chloride (Salt) in WBM.

• Well bore temperature as high as possible

• Select proper Mud Weight to minimize wellhead pressure.

• injecting methanol or glycol at a rate of 0.5 - 1 gal per minutes on the upstream side of a choke

Hydrates

172

Hydrates

173

Wet And Dry Tripping

174

When a length of pipe is pulled from the hole, the

mud level will fall.

Tripping Dry

175

The volume of fall is equal to the volume of steel pulled from the hole.

The trip tank is then used to fill up the hole.

If 1 barrel of steel is removed from the hole,

then using the trip tank, we have to add 1 barrel of

mud.

Tripping Dry

176

1- Calculate the volume of steel pulled:

Length x Metal Displacement

Example:

DP Metal Disp = 0.00764 bbls/ft

Length Pulled 93 feet

Volume Of Steel Pulled:

93 x 0.00764 = 0.711 bbls

Tripping Dry

177

2- Fill up the hole:

You must pump 0.711 barrel of mud from the trip tank.

You must investigate ( flow check) if more mud or less mud

is needed.

Tripping Dry

178

3- NO FILL UP:

If you fail to fill up the hole, the mud level will drop by the

volume of steel pulled.

It will drop inside the pipe and in the annulus.

Tripping Dry

179

3- NO FILL UP:

Example:


93 x 0.00764 = 0.711 bbls

DP Capacity: 0.01776 bbl/ft

Annular Capacity: 0.0504 bbl/ft

The mud will drop inside the pipe and the annular:

0.01776 + 0.0504 = 0.06816 bbl/ft

Tripping Dry

180

3- NO FILL UP:

Example Cont’d:

The volume of drop is 0.711 bbls and will drop in a volume of

0.06816 bbl / ft,

then the length of drop will be:

0.711 / 0.06816 = 10.4 feet.

If 93 feet (1 stand) are pulled with no fill up, the mud level will drop by 10.4 feet.

Tripping Dry

181

When a length of pipe is pulled from the hole, the

mud level will fall.

Tripping Wet

182

The volume of fall is equal to the volume of steel

pulled from the hole plus the volume of mud inside

this pipe.

The trip tank is then used to fill up the hole.

If 3 barrels of steel and mud are removed from the

hole, then using the trip tank, we have to add 3

barrels of mud.

Tripping Wet

183

1- Calculate the volume of steel pulled:

Length x Metal Displacement

Example:

DP Metal Disp = 0.00764 bbls/ft



93 x 0.00764 = 0.711 bbls

Tripping Wet

184

2- Calculate the volume of mud pulled:

Length x DP Capacity

Example:

DP Capacity = 0.01776 bbls/ft


Volume Of Mud Pulled:

93 x 0.01776 = 1.65 bbls

Tripping Wet

185

3- Calculate the total volume of steel and mud pulled:

1.65 + 0.711 = 2.36 barrels

Tripping Wet

186

4- Fill up the hole:

You must pump 2.36 barrels of mud from the trip tank.

You must investigate ( flow check) if more mud or less mud

is needed.

Tripping Wet

187

5- NO FILL UP:

If you fail to fill up the hole, the mud level will drop by the

volume of steel and mud pulled.

It will drop inside the annulus.

Tripping Wet

188

5- NO FILL UP:

Example:

Volume Of Steel and Mud Pulled:

93 x (0.00764+0.01776) = 2.36 bbls

Annular Capacity: 0.0504 bbl/ft

The mud will drop inside the annular by:

2.36 / 0.0504 = 46.9 feet

Tripping Wet

189

It is usefull to pump a slug before tripping.

The slug weight being heavier than the mud, a length of pipe will be empty.

Pumping a Slug

The HP is not reduced because the heavier mud will compensate for the empty pipe.

190

The total HP is the same on both sides of the pipe.

Pumping a Slug

HP mudHP kmw

HP mud

191

Example:

If 20 bbls of 12 ppg slug are pumped in a 10,000 ft hole containing 10 ppg mud, what will be the height of empty pipe?

DP capacity = 0.01776 bbl/ft

Pumping a Slug

1- Calculate the height of the slug:

20 / 0.01776 = 1126 ft

192

Pumping a Slug2- Calculate the HP of the slug:

1126 x 12 x 0.052 = 702.6 psi

702.6 psi

193

Pumping a Slug2- Calculate the HP of the mud in the annulus:

10,000 x 10 x 0.052 = 5,200 psi

702.6 psi 5,200 psi

194

Pumping a Slug3- The total hydrostatic beeing the same on both sides, calculate the HP of the mud below the slug:

5,200 - 702.6 = 4497.4 psi

702.6 psi 5,200 psi

4497.4 psi

195

Pumping a Slug4- Calculate the height of mud needed to give 4497.4 psi as a HP:

TVD = 4497.4 / ( 10 x 0.052 ) = 8648.8 feet

1,126 ft 10,000 ft

8648.8 ft

196

Pumping a Slug4- Calculate the height of empty pipe

10,000 - 8648.8 - 1,126 = 225.2 ft

1,126 ft 10,000 ft

8648.8 ft

225.2 ft

1 Well Control Principles 2 Primary Well Control Secondary Well Control Tertiary Well Control...

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