Drilling Basic 2001 Manual

1© Union Oil of California, dba Unocal 2001All rights reserved

DR

ILLI

NG B

ASIC

TRAINING MANUAL

2

Pressure Basics (The U-Tube)

Kicks & Shut-in

Drillers Method

Gauge QuestionsPressure Lag Time

LOT & Well DesignShallow Hazards

Equipment

Intro

SBM

Special Problems

3

Drilling BasicTable Of Contents

SECTION SLIDE

• Introduction 2-11• Pressure Basics 12-27• U-Tube 28-35• Boyles Law / Inversion 36-43• ECD 44-45• Surge / Swab Pressure 46-50• Kicks Cause & Detection 51-59• Shut-In 60-62• Drills 63-66• Drillers Method 67-103• Kill Weight Mud 104-105• Other Well Control Methods 106-

109

SECTION SLIDE

• Gauge Questions 110-139• Pressure Lag Time 140-169• Well Design / LOT’s 170-207• Shallow Hazards 208-230• Equipment 231-250• Synthetic Fluids 251-269• Special Problems 270-283• Formulas 284-285• Contact Info 286• Appendix

– Glossary– Homework– Simulator Test Sheet– Instructor Evaluation Sheet

4

DRILLING TRAINING GROUP

Rick Dolan - (281) 287-7215 - [email protected]

Benny Mason - (281) 287-7545 - [email protected]

George Grundt - (281) 287-7254 - [email protected]

5

GOALS OF THE COURSE• To increase our understanding

Of the U-Tube Of the Driller’s Method Working together- Teamwork This is not designed as a Certification Course

• To develop (Modify) our approach Dynamic Plan (think) ahead Think smart - Learn smart / Think out of the

box don’t be a robot and blindly follow.• To comply with regulations

Unocal’s Government

6

TRAINING GROUNDRULES

• Stay focused on the agenda

• Everyone is responsible to participate

• One conversation at a time

• All ideas get equal consideration Respect differences There may not be “just” one answer

• Be on time

7

IMPORTANT DETAILS• Manuals - they are yours

• Notes - write in the book or paper

• Problem solving - work as a team (by table)

• FOR THE MONEY- Game show - win prizes

• Homework - DO IT - you will pass the test

• Test - written/simulator

• Relax- The more we work together the more we all learn.

• Parking Lot - Ideas brought up that we are not ready for.

8

OTHER IMPORTANT DETAILSEmergency Exits

No Smoking

Restrooms

Mobile Phones/Beepers

Daily Start - Exactly @ 8 AM

Daily End - Approximately 4:30 PM

Lunch

Breaks

9

WHY WE ARE HERE

• The oil industry spends millions of dollars every year on well control problems. Environmental problems that result from a well control event add to these costs. But well control problems can lead to a loss of something more valuable than money, HUMAN LIFE. Well control problems are not particular. They can occur in big and small companies, exploration, development or workovers, deep or shallow wells, and high pressure (12,000 psi) or low pressure (15 psi). The potential for well control problems and blowouts is ever present.

10

WHY WE ARE HEREThe consequences of failure are severe. Most of these problems were created by a failure to use “BEST PRACTICES” such as:

• Communications/Teamwork• Understanding

• Alertness• Equipment

We’re here to try to eliminate well control problems all together by reminding you to use “BEST PRACTICES”, to work as a team, and get back to basics.

11

You are the chief airplane washer at the company hangar and you:

Hook high pressure hose up to the soap suds machine.

Turn the machine "on".

Receive an important call and have to leave work to go home.

As you depart for home, you yell to Don, your assistant, "Don,turn it off.”

Assistant Don thinks he hears, "Don't turn it off." He shrugs,and leaves the area right after you.

Refer to attachment for the results.

Communications

12


Kicks & Shut-in

Drillers Method



Equipment

Intro

SBM

Special Problems

13

Well ControlWith all the emphasis that we place on mathematics and calculations,Well Control is still as simple as a playground teeter-totter. As we continue learning how to calculate BHP, Hydrostatic Pressure, Gradients, Volumes and Force - Keep in mind this simple picture.

Hydrostatic = 5000 psi Hydrostatic = 5000 psi

BHP = 5000 psi

0psi 0psi

14

Pressure

0

1 lb1 lb1 lb

123

The total force felt downward is 3 lbs but is this a pressure?

lb

15

Pressure

1 lb

1 lb

1 lb

0123

The force felt downward is still 3 lbs but it is felt over a total surface area of 1 square inch. Is this pressure?

Force = 3 lbs = 3 psiArea 1 sq. in.

lb

1” 1”

16

0 lb

1”1”

1’

PressureIn our industry, when we are measuring pressure it is usually pressure createdwith a fluid. We will describe most of these pressures in our Well Control class. For now lets talk about fluid at rest.

Fluid at rest creates a pressure that we call Hydrostatic Pressure.

hydro (Fluid) static (at rest)

Weightof

Fluid

PSIhydrostatic = Fluid Weightppg x 0.052 x Vertical Height of fluid

17

What is 0.052?

12” X 12” = 144 in2

12”

12”

12”1”

1”

1 ft. = 0.052 gal.

A one cubic foot container will hold 7.5 gallons of fluid.Because we are measuring our pressure in square inches, we section the base into square inches.

If I now divide the 7.5 gallons by 144 square inches, we find that a column of fluid 1in X 1in X 1ft tall contains 0.052 gallons of fluid.

18

Gradient

1”1”

1 ft. = 0.052 gal.

If our fluid density is measured in ppg you can then multiply the fluid weight (ppg) by 0.052 to find the hydrostatic pressure (psi) exerted by one foot of this fluid. This is called the “pressure gradient” (G) of the fluid or the pressure change per foot (psi/ft).

Gradientpsi/ft = Fluid Weightppg x 0.052 x 1ft

If we fill the 0.052 gallon container with 10 ppg fluid, what will be the pressure?

10ppg x 0.052gal/sq. in./ft = Pressureft

10 x 0.052 = .52 psift

This means that for every foot of mud in the well, the pressureincreases by .52 psi. So, Gradientpsi/ft x TVDft = Pressurehydrostatic

19

11’10’

TVD vs MDBecause fluid density is a function of gravitational force and gravity is a vertical component, the bottomhole hydrostatic pressure is the sum of all the vertical components. The sketch of a slant hole helps us see why this is true. It shows that the mud column can be thought of as a stack of blocks, with the weight of each block pushing vertically downward on those underneath it. From this, we see that it is the vertical height (or depth) of a mud column, not its measured length, that must be used in pressure calculations.

20

Pressure Equations•Hydrostatic Pressure (psi) = MW (ppg) X 0.052 X Depth (ft)

HP = PPG X 0.052 X TVD

•Gradient (psi/ft) = Fluid Weight (ppg) X 0.052 G = MW X 0.052

•Hydrostatic Pressure (psi) = Gradient (psi/ft) X Depth (ft.)HP = G X TVD

•Equivalent Mud Weight (ppg) = Gradient (psi/ft) 0.052EMW = G 0.052 or EMW = Press. (TVD

x 0.052)•Gradient (psi/ft.) = Pressure (psi) Depth (ft.)

G = P TVD

Bottom Hole Pressure = Hydrostatic Pressure + Gauge

21

Equation Triangle

Pressurepsi

Pressurepsi =

MWppg

MWppg

X

X

0.052

0.052

X

X

TVDft

TVDft

If you want to solve for MW or TVD, fill in the known information and the equation is written for you.

22

Equation Triangle

Pressurepsi

MWppg X 0.052 X TVDft

1) SIDPP is 500 psi. Hole TVD is 11,000 ft.How much MW increase is needed to kill the well?

_______ppg

500 psi

? 11000 ft

500 psi MWppg =

0.052

0.052 x 11000 ft

On your calculator you would key in:• 0.052 x 11000 = 572• 500 572 = .87ppg

.87


MWppg = 500 572

23

Equation Triangle

Pressurepsi

MWppg X 0.052 X TVDft


1) While pulling out of the hole, using 9.6 ppg fluid, you forgot to fill the hole. If your overbalance is 100 psi, how far can the fluid level drop before you are underbalance?

_______ft

FT =

?

100 psi 100psi 9.6ppg x

9.6ppg 0.052

0.052

FT = 100 .5

On your calculator you would key in:• 9.6 x 0.052 = .5 psi/ft

• 100 .5 = 200ft

200

24

FORMATION PRESSURES

8.4 ppg > Normal Pressured formations < 8.9 ppg Abnormal Pressured formations > 8.9 ppg

8.4 ppg > Subnormal Pressured formationsAs the weight of the sponges increases, the fluid is squeezed out.If you make a hole in the bottom sponge nothing happens.

If the bottom sponge is wrapped in plastic (sealed) then the fluid cannotescape and becomes pressurized bythe weight of the sponges above. If youmake a hole in the bottom sponge:

25

Pformation= 4500 psi

FORMATION PRESSURESNormal, Abnormal &

Subnormal

A10,000’

B8,000’

4,500 10,000 = .45 psi/ft.45 0.052 = 8.7 ppg

4,500 8,000 = .56 psi/ft.56 0.052 = 10.8 ppg

Formation pressure of 4,500 psi at 8,000’ would be considered Abnormal pressure!

26

COMMUNICATION TO SURFACE CAN BE

HARMFUL TOYOUR WELL BEING!

CHARGED SANDS

Poor cement practices can lead to communication outside the casing.

27

Up Structure Locations-Normally Pressured Fields

GAS

PA = 4100’ x .465 psi/ft = 1906 psi MW a = 8.9 ppg

SAND

WELL A

3600’

3900’

4000’

4100’ SHALE

SHALE

A

B

C

D

WELL B WELL C WELL D“NORMAL” GRADIENT

ALL ZONES

PB = 4000’ x .465 psi/ft = 1860 psi MW b = 8.9 ppg

PC = PB= 1860 psi G = 1860 / 3900ft = .477 psi/ft MW C = 9.2 ppg

PD= PC= PB= 1860 psi G = 1860 / 3600ft = .517 psi/ft

MW D = 9.9 ppg

GAS/ WATER CONTACT

28

U- Tube

10,000 ft

While drilling a well, we have a u-tube in effect.

The workstring and the annulus form our u-tube.

The gauge should be Bottom Hole Pressure.

29

If I started filling the glass tube with a fluid that weighed 9.6 ppg where would the fluid go and what would the gauge read?

10 ft

9.6ppg x 0.052 x 10ft = 5

U- Tube

30

If I then put another few gallons of a 12 ppg fluid in the tube what would happen and what would the gauge read?

10 ft

= 9.6ppg x 0.052 x 10ft5

Two columns of fluid connected at the bottom that will balance each other in a static condition.

U- Tube

31

U- TubePractice

6000 ft

6000 ft TVD

1,500 ft of 13.6 ppg

AIR

4,000 ft of 10.2 ppg

10.2 ppg

Calculate Bottom Hole Pressure

32

U- TubePractice

6000 ft TVD

Calculate Bottom Hole Pressure

6000 ft

1,000 ft of 10 ppg

5,000 ft of 9.6 ppg

5,500 ft of 10 ppg

500 ft of 6 ppg

336000 ft TVD

Calculate how far the slug has dropped.

6000 ft

6,000 ft of 10.5 ppg

1,200 ft of 12 ppg

U- TubePractice

34

U- TubePractice

6000 ft TVD

If there is no balance between the two columns of fluid and the fluid cannot escape, pressure will be created.

6,000 ft of 12.5 ppg 6,000 ft of 10 ppg fluid

6000 ft

BHP =

= Gauge Press.

35

Well Control

Remember:

Hydrostatic = 3900 psi Hydrostatic = 3120 psi

BHP = 3900 psi

0psi 780psi

36MUD 2000’ 10 LONG

1500’ 13.5’ LONG

1000’ 20’ LONG

500’ 40’ LONG

0’ 600-1200’ LONG

Uncontrolled Expansion

37

New Hydrostatic (9.6 X 0.052) X 1000 = 500 psi

P2 = 500 psiV2 = 100 bblsP2 = Where?V2 = ? bbls P2 = 500 psi

V2 = 1000 bblsP2 = Where?V2 = ? bbls

P2 = 2500 psiV2 = 20 bblsP2 = Where?V2 = ? bbls

New Hydrostatic =(9.6 X 0.052) X 100 =50 psi

? bbls GasTop of gasat 100 ft.

GAS EXPANSIONV2 = (P1 X V1) P2

10 bbls gas

Hydrostatic =(9.6 X 0.052) X 10,000 =5000 psi

New Hydrostatic =(9.6 X 0.052) X 5000 =2500 psi



P1 = 5000 psiV1 = 10 bbls

38

Equation Triangle

P1 x V1

XP2 V2

P1 x V1 XP2 V2=P1 is the pressure that the gas is under.

P1 = BHP

V1 is the size of kickV1 = Barrels

P2 is the pressure of the gas at it’s new position in the well.

P2 = Hydrostatic + Gauge Pressure

V2 is the new size of the kick at it’s new position in the well.

V2 = Barrels

39

Equation Triangle

P1 x V1

XP2 V2

P1 x V1 XP2 V2=

?

P1 = 5000 psiV1 = 10 bbls

5000 X 10

P2 = 14.7 psi

14.7

V2 = ?

5000 X 10 14.7

On your calculator you would key in:• 5000 x 10 = (50,000) 14.7 =

= 3,401 bbls

40

Volume At Surface

12.4 ppg WBM The well unloaded 30 bbls at Bottoms Up.

6” Open Hole to TD@12,000

• P1 = 14.7 psi• V1 = 30 bbls• P2 = 12.4 x 0.052 x 12,000 = 7,740 psi• V2 = 0.057 bbl kick on Bottom

Can you detect a kick this size?

41

PRESSURE INVERSION

250 Gauge Press.+ 4930 Hydrostatic 5180 psi Gas Press.

250 Gauge Press.+ 2500 Hydrostatic to shoe 2750 psi at casing shoe

250

143 ft

Hydrostatic = (10000 – 143) X 0.052 X 9.6= 4930 psi

42

PRESSURE INVERSION

143 ft

2680

5180 psi at shoe- 2500 Hydrostatic to shoe 2680 Gauge Press.

5180 Gas Press.+ 2430 Hydrostatic 7610 psi Bottom Hole

Hydrostatic =5000 X 0.052 X 9.6 = 2500 psi

Hydrostatic =(5000 – 143) X 0.052 X 9.6= 2430 psi

5180

43

PRESSURE INVERSION

143 ft

5180

5180

Hydrostatic = (10000 – 143) X 0.052 X 9.6 = 4921 psi

5180 Gas Press.+ 2430 Hydrostatic at shoe 7610 psi at shoe

5180 Gas Press.+ 4921 Hydrostatic10,101 psi Bottom Hole

44

ECD2300

2150

1405 115

0

Drillstring frictionloss = 745 psi Friction loss

at bit = 1290 psiAnnular friction loss (AFL) = 115 psi

Annular Open

TVD = 10,000 ft

Mud Weight = 10 ppg

SPM = 100

Hydrostatic = 10 X 10,000 X 0.052 = 5,200 psi

Friction lossin surface lines= 150 psi

Circulating BHP = 5,200 + 115 = 5,315 psi

ECD = 5,315 ÷ 10,000 ÷ 0.052 = 10.22 ppg

45

ECD2300

2150

745 2035

0

Drillstring frictionloss = 745 psi Friction loss

at bit = 1290 psiAnnular friction loss (AFL) = 115 psi

Annular Closed

TVD = 10,000 ft

Mud Weight = 10 ppg

Hydrostatic = 10 X 10,000 X 0.052 = 5,200 psi

Friction lossin surface lines= 150 psi

SPM = 100

Reverse Circulate

Circulating BHP = 5,200 + 2,035 = 7,235 psi

ECD = 7,235 ÷ 10,000 ÷ 0.052 = 13.91 ppg

46

Swab PressureIn a static condition, Bottom hole pressure is equal to Hydrostatic Pressure.

As the pipe is pulled out of the hole, friction creates a swabpressure that is felt upward.

Swab Pressure

BHP = 10,000 X 10 X 0.052 = 5,200 psi

10,000 ft

10 ppg

Formation Pressure = 5,100 psi

47

Swab Pressure

10,000 ft

10 ppg

Formation Pressure = 5,100 psiBHP = (10,000 X 10 X 0.052) - 150 psi = 5,050 psi

In this example, the swab pressure created is 50 psi more than the overbalance. This would let formation fluid into the well.

If the swab pressure is greater than the overbalance,fluid in the formation can enter the well.

Swab Pressure = 150 psi

48

Swab Pressure

10,000 ft

10 ppg

Formation Pressure = 5,100 psiBHP = 10,000 X 10 X 0.052 = 5,200 psi

Even though the overbalance is restored, the fluid thatwas swabbed in is still in the well.

When the pipe movement is stopped, the friction is lost,and the overbalance is returned.

This influx would have little or no migration and no noticeable expansion. A flow check would not show any flow.

BUT THERE IS A KICK IN THE WELL!!

49

Swab Pressure

10,000 ft

10 ppg

Factors that create swab pressure are:

• Clearance

• Yield Point of mud

• Pulling Speed of Pipe

• Length of Drillstring

50

Surge Pressure

10,000 ft

10 ppgFactors that create surge pressure are:

• Clearance

• Yield Point of mud

• Running Speed of Pipe

• Length of Drillstring

Surge Pressure is a downward force create by lowering the drillstring and creating friction as the mud is displaced from the hole. This surge pressure increases BHP.

High surge pressure can cause the formations tofracture and lost circulation to occur.

Surge Pressure = 150 psi

51


Kicks & Shut-in

Drillers Method



Equipment

Intro

SBM

Special Problems

52

TRENDS IN KICK DECTECTION,JUST LIKE DRILLING

• What are the trends

• How do you recognize the trends

• Teamwork

• Think and react

53

KicksCause

THE MAIN CONDITION THAT ALLOWS A KICK TO OCCUR:

THE PRESSURE IN THE WELL BORE BECOMES LESS THAN THE PRESSURE IN THE FORMATION

54

Decreasing Occurrence

1. Failure to keep hole full of drilling fluid.

Measurement of fill-up volume when pulling drill string (and of displacement volume while running)

TRIP TANK!

2. Drilling into zones of known pressure withmud weight too low.

Good engineering/good well procedures and alert, questioning attitude by Foreman.

ALERTNESS

3. Drilling into anunexpected abnormal formation pressure.

Careful engineering;proper well design;Understand the Geology; Use Pressure Hunting Techniques

STUDY OFFSET WELLS!

55

4. Lost Circulation

(Fluid level, not rate of loss is critical in well control.)

Careful engineering; proper well design;Understand the Geology

CASE OFF LOST CIRC. ASAP!

5. Unloading mud by pullingballed drilling assembly.

Measurement of fill-up volume when pulling drill string.

TRIP TANK!

6. Mud weight high enoughto drill but not to trip.

Measurement of fill-up volume when pulling drill string.

TRIP TANK!

Decreasing Occurrence

56

GULF COAST STATISTICS FROM 1960 TO 1996

THERE WERE 1,206 KICKS REPORTED

A BLOWOUT OCCURS FOR ABOUT EVERY 110 KICKS

• EXPLORATION DRILLING - 30%

• DEVELOPMENT DRILLING - 22%

• COMPLETIONS - 8%

• WORKOVERS - 24%

57

GULF COAST STATISTICS FROM 1960 TO 1996

DRILLING STATISTICS

• TRIPPING OUT - 37%

• DRILLING - 35%

• OUT OF THE HOLE - 4%

• TRIPPING IN - 3%

• CIRCULATING - 0.5%

58

DETECTION OF KICKS WHILE DRILLING

SIGN HOW TO CHECK IT OUT

1. Increase in Flow-line discharge

Stop pumps & check for flow

2. Increase in pit volume

3. Drilling break- Real time LWD response.



Notes: Don’t assume that a small flow is not a kick. Observe well long enough to be sure. Put well on Trip Tank to check small flows, when drilling top of hole at high ROP

CHECK FOR FLOW ON CONNECTIONS

59

Flow Checking

If the well continues to flow after the pumps are off, then:

SHUT THE WELL IN

There are several reasons which might cause the well to flow with the pumps turned off, the main three are:

• Unbalanced U-Tube

• Ballooning or Fracture Charging

• There is a kick in the well !

However, it is recommended to SHUT THE WELL IN until it is determined the flow is not caused by underbalance.

60

SHUT-IN PROCEDURE

KEEP PATHS ON CHOKE MANIFOLD CLOSED In general, the use of a float while drilling is recommended.

WHILE DRILLING

1. Pull up and position T.J. above rotary table.NOTES:

1. When well has

been shut-in and readable pressures have been observed, do NOT open well to verify entry or check its rate.

2. Decide on max. CP

for pipe Movement

AHEAD OF TIME

2. Shut down pump.

3. Check for flow.

4. Close annular preventer (“Hydril”) AND Open HCR valve.

5. Toolpusher and Drilling Foreman on floor.

6. Read/record SIDPP and SICP.

7. Start moving pipe if reasonable.

8. Read/record gain in pit volume.

61

SHUT-IN PROCEDUREWHILE TRIPPING

1. Set slips with T.J. positioned above rotary table.2. Install full-opening safety valve in open position.

3. Close safety valve.

4. Close annular preventer (“Hydril”)

ANDOpen HCR valve.

5. Toolpusher and Drilling Foreman on floor.

6. Put on Top Drive and open safety valve.


8. Start moving pipe if reasonable.


NOTES:

1. When well has been

shut-in and readable pressures have been observed, do NOT open well to verify entry or check its rate.

2. Decide on max. CP for

pipe movement

AHEAD OF TIME

3. Install inside BOP

If needed in control procedure.

62

ROLES & RESPONSIBLITIESDrilling Foreman - Manages and directs all activities at the rig site.

Rig Crews - Execute the plan as directed by the Foreman, maintain and ensure all equipment working properly

Drilling Engineer - Designs well, works with G&G on pore pressure and fracture gradient prediction. Also provides technical support to Drilling Foreman.

Drilling Superintendent - Provides technical support and coordinates the activities by Foreman and Engineer.

63

DRILLS

• DRILLS SHOULD BE CONDUCTED AT AN OPTIMUM TIME.

• Drills are not a competitive sporting event. A five-minute drill indicates that your crew is conducting these drills and hopefully improving. A 30-second drill indicates that you are not doing them properly.

• Keep kick detection in everyone’s mind.

• Gives you information that may be useful during a kill.

• Gives you practice with the actual equipment.

• Gives you confidence if you actually are in a well control situation.

• Establishes Roles and Responsibilities of Crews.

64

KICK DRILL

Pit Drill/Flow Drill

Action Responsible PartyInitiate Drill Unocal Foreman/Rig ManagerLift flow sensor or Pit float to indicate “kick”Immediately record start time.

Recognize “Kick” Driller/LoggerLogger should notify Driller of indicator.Driller to stop drilling, pick up off bottom and stop pumps.Conduct flow check.

Initiate Action Unocal Foreman/Rig ManagerNotify drill crew that the well is “flowing” (Drill)

Simulate Shut-in Driller/CrewMove to BOP Panel.

Time is stopped. Record this time in the Drilling Report.

65

TRIP DRILLPit Drill/Flow Drill

Action Responsible PartyInitiate Drill Unocal Foreman/Rig ManagerLift flow sensor or Pit float to indicate “kick”Immediately record start time.

Recognize “Kick” Driller/LoggerLogger should notify Driller of indicator.Driller to stop drilling, pick up off bottom and stop pumps.Conduct flow check.

Initiate Action Unocal Foreman/Rig ManagerNotify drill crew that the well is “flowing” (Drill)

Simulate Shut-In Driller/CrewPosition tool joint above rotary and set slips.Stab FOSV and close valve.Latch elevators or make-up top drive and remove slips.Move to BOP panel.

Time is stopped. Record this time in the Drilling Report.

H2S drills are conducted the same as above, however upon notification that the drill is in progress the crew will don breathing apparatus before taking any further action.

66

CHOKE DRILL

1. Before drilling out each casing shoe. Trap a small amount of pressure against the choke. Practice proper start- up of the Driller’s Method holding this pressure constant.

2. After moving to the Drillpipe Pressure gauge and allowing the pressures in the well to stabilize, make a definite change on the Casing gauge (50 -100 psi) by opening or closing the choke.

3. Record the time required to see this pressure change reflect on the Drillpipe gauge.

This is PLT (Pressure Lag Time)

67


Kicks & Shut-in

Drillers Method



Equipment

Intro

SBM

Special Problems

68

Well is shut in and pressures allowed to stabilize.

Shut-in Drillpipe pressure + DP Hydrostatic = Bottom Hole Pressure.

Kill the well using the Drillers Method.

TVD = 10,000 ft.

CLOSE OPEN

300500

DP300

CP500

BHP5,500

69TVD = 10,000 ft.

CLOSE OPEN

300500

DP300

CP500

BHP5,500

Mud weight = 10ppg

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

BHP = 5,200 + 300 = 5,500 psi

70TVD = 10,000 ft.

CLOSE OPEN

300500

DP300

CP500

BHP5,500

KRP @40 spm = 1,000psiICP = 1000 + 300 = 1,300 psi on DP

From your last “choke drill” we know;

71

CLOSE OPEN

500

Casing Pressure is held constant as pumps are brought up to speed by opening the choke.

If the Casing Pressure is held constant when starting, then BHP is held constant.

Once pumps are up to speed, the Drillpipe Pressure should be held constant to keep BHP constant.

DP1300

CP500

BHP5,500

1300

72

CLOSE OPEN

550

As the bubble begins to expand it pushes mud out of the hole causing a loss of hydrostatic. To keep BHP constant, Drillpipe pressure must be kept constant.

BHP5,500

DP1300

CP550

1300

73

CLOSE OPEN

650DP

1300CP650

BHP5,500

1300

74

CLOSE OPEN

625DP

1300CP625

BHP5,500

1300

75

CLOSE OPEN

600DP

1300CP600

BHP5,500

1300

76

CLOSE OPEN

5501300

DP1300

CP550

BHP5,500

77

CLOSE OPEN

700DP

1300CP700

BHP5,500

1300

78

CLOSE OPEN

1000DP

1300CP

1000

BHP5,500

1300

79

CLOSE OPEN

1750DP

1300CP

1750

BHP5,500

1300

80

CLOSE OPEN

1000DP

1300CP

1000

BHP5,500

1300

81

CLOSE OPEN

400DP

1300CP400

BHP5,500

1300

82

CLOSE OPEN

3001300

Once the influx is circulated out, casing pressure should be held constant while the pumps are brought down and the well shut-in.

DP1300

CP350

BHP5,500

83

CLOSE OPEN

300300

Compare the Drillpipe and Casing pressure gauges and confirm that they are equal. If Casing pressure is greater than Drillpipe pressure then you may not have all the influx out of the well.

Once you are confident that the annulus is clean line up the pumps on Kill Weight Fluid.

DP300

CP300

BHP5,500

84

CLOSE OPEN

Hold Casing pressure constant as you bring the pumps up to 40 spm.

Continue to hold Casing pressure constant as you displace the drillstring.

Drillpipe pressure should drop as hydrostatic in the drillpipe increases.

300DP

1300CP300

BHP5,500

1300

85

CLOSE OPEN

300DP

1250CP300

BHP5,500

1250

86

CLOSE OPEN

300DP

1200CP300

BHP5,500

1200

87

CLOSE OPEN

300DP

1150CP300

BHP5,500

1150

88

CLOSE OPEN

300DP

1100CP300

BHP5,500

1100

89

CLOSE OPEN

Once the Drillpipe is full of Kill Weight Fluid the hydrostatic will remain constant.

Continue circulating holding Drillpipe pressure constant at FCP.

Casing pressure should drop as Kill Weight Fluid displaces the annulus.

300DP

1060CP300

BHP5,500

1060

90

CLOSE OPEN

300DP

1060CP300

BHP5,500

1060

91

CLOSE OPEN

250DP

1060CP250

BHP5,500

1060

92

CLOSE OPEN

200DP

1060CP200

BHP5,500

1060

93

CLOSE OPEN

150DP

1060CP150

BHP5,500

1060

94

CLOSE OPEN

100DP

1060CP100

BHP5,500

1060

95

CLOSE OPEN

50

BHP5,550

DP1110

CP50

BHP = HP + CP= 5,500 + 50 = 5,550psi

1110

96

CLOSE OPEN

0

After confirming that Kill Weight Fluid is back to surface, shut the well in.

Drillpipe and Casing pressure should read 0 psi.

Open the choke and check for flow. When opening the Annular beware of gas trapped under the element. BHP

5,500

DP0

CP0

0

97

DRILLERS METHOD

> Monitor shut-in well while preparing to start circulating using original weight fluid. Record Drillpipe & Casing pressures.

> Hold Casing Pressure constant while bringing pump up to kill rate speed. THIS SPEED IS TO BE HELD CONSTANT.

> Hold Casing Pressure constant a few more minutes until DP pressure stabilizes.

> Read DP Pressure and hold this pressure constant until the kick is circulated out of the hole.

> Hold Casing Pressure constant while bringing pump speed down. When pump speed is down to the point that the pump is barely running:

-Shut pump off (first) -Finish closing choke

> Read Pressures. If all influx is out of well the pressure should be almost the same.

FIRST STEP ( Remove Influx)

98

DRILLERS METHOD

> Calculate kill weight and increase fluid weight to that value.

> Hold Casing Pressure constant while bringing pump up to kill rate speed. THIS SPEED IS TO BE HELD CONSTANT.

> Hold Casing Pressure constant until drill string volume has been pumped.

> Read DP Pressure and hold this pressure constant until fluid returns are at kill weight.

> Shut down pump and shut in well.

> Read pressures. Should be zero.

> Check for flow through choke line.

> Open preventers if well is dead.

SECOND STEP (Change Fluid Weight)

99

Choke Position

Open Closed

10,000 ft

9.6 ppg

Formation Pressure= 6000 psi

800 1000

BHP = HYD + GAUGE• If the kick was larger in

size would DP and CP change?

• If the kick was salt water or gas would DP and CP change?

• If a gas bubble began to migrate, how would you control bottom hole press?

• If the hole size was smaller would it change DP and CP?

100

Choke Position

Open Closed

10,000 ft

9.6 ppg


1500 1100

BHP = HYD + GAUGE

Pumps are constant at 40 spm.

As the bubble expands, what happens to hydrostatic pressure in the annulus?

What happens to hydrostatic in the DP?

If the DP gauge is kept constant, what happens to BHP?

If the CP gauge is kept constant, what happens to BHP?

101

Choke Position

Open Closed

10,000 ft

9.6 ppg


1300 800

BHP = HYD + GAUGE

Pump strokes are constant at 40 spm

As KWF is being pumped, what is happening to the hydrostatic pressure in the DP?

If the annulus is clean, what is happening to the hydrostatic in the annulus?

If CP is held constant what happens to BHP?

If DP pressure is held constant what happens to BHP?

102

Choke Position

Open Closed

10,000 ft

9.6 ppg


700 780BHP = HYD + GAUGE

Pump strokes are constant at 40 spm

As KWF is pumped up the annulus, what is happening to the hydrostatic in the DP?

As KWF is pumped up the annulus, what is happening to the hydrostatic in the annulus?

If you hold DP constant, what happens to BHP?

If you hold CP constant, what happens to BHP?

103

Pressure Lag Time10001500

TD @ 23,000 ft.

A closing/opening adjustment on the choke would take 23 seconds to travel down the annulus and 23 seconds to travel up the drillpipe before reflecting on the drillpipe gauge with water base mud.

With SBM/OBM, the compressibility of the oil will increase the lag time. On one documented well, with casing set at 14,000’ it took 3-4 min. before the choke adjustments were reflected on the drillpipe gauge.

To get an estimate of what the lag time can be, chokedrills, prior to drilling out the casing shoe, are recommended.

1600

104

CALCULATION OF KILL WEIGHTGiven: DEPTH (TVD) = 8000’

ORIGINAL MUD WEIGHT = 11 PPGSHUT-IN DP PRESSURE = 700 PSI

BHP = SIDPP + Hydrostatic= 700 + (11 X 0.052 X 8000)= 700 + 4576= 5276 psi

KMW = BHP 0.052 TVD=5276 0.052 8000= 12.68

12. 6 ppg or 12.7 ppg ?

105

8.5 “

0

9,000 ft.

SICP

3,000 ft.

9.625”

Kill Mud

Original Mud

USE OF SAFETY FACTOR IN CALCULATION OF KILL WEIGHT MUD

GIVEN:

TD= 9000’

9 5/8” casing shoe @ 3000’

8 1/2” open hole

5” drill pipe

10 ppg original mud weight

Original SIDPP = 500 psi

Shoe tested to Leak-off @ 14 ppg EMW

Assume pump is shut off when drill pipe is filled with kill mud.

KWM used Safety Factor SICP EMW @ Shoe Over/under LOT (ppg) (ppg) (psi) (ppg) (ppg) 11.1 0 515 13.3 .7 under 11.2 .1 550 13.6 .4 under 11.3 .2 610 13.9 .1 under 11.5 .4 700 14.5 .5 over 12.1 1.0 980 16.3 2.3 over

106

CASING PRESSURE CURVESWELL DEPTH = 8000’ HOLE SIZE = 12-1/4”DRILL PIPE = 5”, 19.5# MUD WT. = 9.6 ppgKILL WT. = 10.6 ppg

0

200

400

600

800

1000

1200

0 200 400 600 800 1000 1200 BBLS PUMPED

CA

SIN

G P

RES

SUR

E, P

SI 40 bbl KICK

20 bbl KICK

10 bbl KICK

BEGIN 2nd.CIRCULATION

107

CASING PRESSURE CURVESWELL DEPTH = 8000’ MUD WEIGHT = 9.6 ppgHOLE SIZE = 12-1/4” KILL WEIGHT = 10.6 ppgDRILL PIPE = 5”, 19.5# KICK VOLUME = 20 bbls

0

200

400

600

800

1000

CA

SIN

G P

RES

SUR

E, P

SI

DRILLER'S METHOD

WITH 2000' MIGRATION

WAIT & WEIGHT METHOD

WITH NO MIX TIME

GAS AT SURFACE

KILL WEIGHT MUD AT BIT

108

400

500

600

700

800

900

1000

1100

1200

1300

0 1000 2000 STROKES

DR

ILL

PIPE

PR

ESSU

RE

Conventional Drill Pipe Schedule

Correct Drill Pipe Schedule

Amount of Overbalance

DEVIATED WELL PRESSURE DROP CURVES

60 HOLE WITH KICK-OFF AT 1/3 TMD

109

OTHER WELL CONTROL METHODSUNOCAL PREFERRED METHOD

A. Driller’s Method

OTHER ACCEPTABLE METHODSA. Wait & Weight MethodB. Top KillC. Bottom KillD. Lubricate & BleedE. Volumetric (does not kill the well)F. Bullhead

These Methods Are NOT Preferred

110


Kicks & Shut-in

Drillers Method



Equipment

Intro

SBM

Special Problems

111

WELL INFORMATION

• TVD = 10,000 ft.• Shoe TVD = 7500 ft.• Fluid Weight = 9.6 ppg.• Circulating Rate = 50 spm.• Influx is Gas.• Water Base Mud

• Strokes To Bit = 1,570.• Bottoms Up Strokes = 5,550.• Strokes To Shoe = 1,390.• Total Strokes = 7,120.• M.A.S.P. @ 9.6 ppg = 1,100 psi

112

1000

2000

3000

0

1000

2000

3000

0

OPEN CLOSED

1/81/4

3/81/25/83/4

7/8SPM

TOTAL STROKES

DRILLPIPE CASING

Pit Gain

At initial shut-in, these are the stabilized pressures that you read.

500 800

10 bbls. 0

0

113

A. The sameB. 800 psi each ± 0 pit gain.C. DP -500/CP-800 ± 0 pit gain.D. 500 psi each ± 10 bbl pit gain.

E. 500 psi each ± 0 pit gain.

1000

2000

3000

0

1000

2000

3000

0

OPEN CLOSED

1/81/4

3/81/25/83/4

7/8SPM

TOTAL STROKES

DRILLPIPE CASING

Pit Gain

Before you get started, what will the gauges and the pit volume bewhen you get finished with the first step of the Driller’s Method?

500 800

10 bbls. 0

0

114

A. 9.6 PPGB. 10.6 PPG.C. 8.6 PPG.D. 9.0 PPG.

E. 10.0 PPG. 1000

2000

3000

0

1000

2000

3000

0

OPEN CLOSED

1/81/4

3/81/25/83/4

7/8SPM

TOTAL STROKES

DRILLPIPE CASING

Pit Gain

Before you get started, what mud weight should be used?

500 800

10 bbls. 0

0

115

E. Begin monitoring DP gauge

D. Choke size OK

Pit Gain

1000

2000

3000

0

1000

2000

3000

0

OPEN CLOSED

1/81/4

3/81/25/83/4

7/8SPM

TOTAL STROKES

DRILLPIPE CASING

1500 800

50

15010 bbls.

The pumps are brought up to Kill Rate Speed and this is what you see. Which of the following courses of action would you take?

A. Continue holding CP constantB. Open choke

C. Close Choke

F. Shut the well in

116

Pit Gain

1000

2000

3000

0

1000

2000

3000

0

OPEN CLOSED

1/81/4

3/81/25/83/4

7/8SPM

TOTAL STROKES

DRILLPIPE CASING

1500 800

50

30011 bbls.

A. Decrease stroke rateB. Open choke

C. Close Choke

D. Choke size OK

E. Increase stroke rate

You’ve been circulating for a few minutes and everything seems to be ok.Which of the following courses of action would you take?

F. Shut the well in

117

B. Open choke

Pit Gain

1000

2000

3000

0

1000

2000

3000

0

OPEN CLOSED

1/81/4

3/81/25/83/4

7/8SPM

TOTAL STROKES

DRILLPIPE CASING

1800 800

50

50011 bbls.

Casing pressure decreased slightly so you pinched the choke in and this is what you see. Which of the following courses of action would you take?

A. Decrease stroke rate

C. Close Choke

D. Choke size OK


F. Shut the well in

118

Pit Gain

1000

2000

3000

0

1000

2000

3000

0

OPEN CLOSED

1/81/4

3/81/25/83/4

7/8SPM

TOTAL STROKES

DRILLPIPE CASING

1500 750

45

75011 bbls.


C. Close Choke

D. Choke size OK


Drillpipe pressure was a little to high so you corrected the problem and this iswhat you see. Which of the following courses of action would you take?

F. Shut the well in

119

Pit Gain

1000

2000

3000

0

1000

2000

3000

0

OPEN CLOSED

1/81/4

3/81/25/83/4

7/8SPM

TOTAL STROKES

DRILLPIPE CASING

1500 950

50

95012 bbls.


C. Close Choke

D. Choke size OK


You finally get things back to where you like and this is what you see. Which of the following courses of action would you take?

F. Shut the well in

120

Pit Gain

1000

2000

3000

0

1000

2000

3000

0

OPEN CLOSED

1/81/4

3/81/25/83/4

7/8SPM

TOTAL STROKES

DRILLPIPE CASING

1500 1000

50

120012 bbls.


C. Close Choke

D. Choke size OK


The Casing pressure is getting close to your posted MASP. Which of the following courses of action would you take?

F. Shut the well in

121

Pit Gain

1000

2000

3000

0

1000

2000

3000

0

OPEN CLOSED

1/81/4

3/81/25/83/4

7/8SPM

TOTAL STROKES

DRILLPIPE CASING

1500 1150

50

160012 bbls.


C. Close Choke

D. Choke size OK


It’s decision time, earn your pay. Which of the following courses of action would you take?

F. Shut the well in

122

A. Decrease stroke rate

Pit Gain

1000

2000

3000

0

1000

2000

3000

0

OPEN CLOSED

1/81/4

3/81/25/83/4

7/8SPM

TOTAL STROKES

DRILLPIPE CASING

1500 1250

54

350017 bbls.

B. Open choke

C. Close Choke

D. Choke size OK


It’s starting to get boring now. The driller has gone for a smoke and the ADis on the floor. Before you let him take over, you see this. Which of the following courses of action would you take?

F. Shut the well in

123

A. Pit volume goes down and casing gauge goes up.

1000

2000

3000

0

1000

2000

3000

0

OPEN CLOSED

1/81/4

3/81/25/83/4

7/8SPM

TOTAL STROKES

DRILLPIPE CASING

1500 1250

50

4500

B. Pit volume goes up and casing gauge goes up.C. Pit volume goes down and casing gauge goes down.D. NothingE. Pit volume goes down and casing gauge goes up.

You hear gas passing through the choke. What will happen to the casinggauge and to the pit volume as the gas is circulated out?

Pit Gain

27 bbls.

F. Pit volume goes up and casing gauge goes down.

124

Pit Gain

1000

2000

3000

0

1000

2000

3000

0

OPEN CLOSED

1/81/4

3/81/25/83/4

7/8SPM

TOTAL STROKES

DRILLPIPE CASING

1500 200

50

450027 bbls.


C. Close Choke

D. Choke size OK


You hear gas passing through the choke and the Casing gauge begins too drop. Which of the following courses of action would you take?

F. Shut the well in

125

Pit Gain

1000

2000

3000

0

1000

2000

3000

0

OPEN CLOSED

1/81/4

3/81/25/83/4

7/8SPM

TOTAL STROKES

DRILLPIPE CASING

550 700

0

55506 bbls.

A. Open choke and flow checkB. Line up on KW Mud

C. Continue to circulate

D. Call town

E. Increase Kill Weight Mud

You got behind the kick and played “choke handle tennis” but finally got the gasout and the well shut-in. Which of the following courses of action would you take?

F. Shut the well in

126

Pit Gain

1000

2000

3000

0

1000

2000

3000

0

OPEN CLOSED

1/81/4

3/81/25/83/4

7/8SPM

TOTAL STROKES

DRILLPIPE CASING

1500 550

50

65504 bbls.


C. Close Choke

D. Choke size OK


You elected to circulate longer and this is what you see. Which of the following courses of action would you take?

F. Shut the well in

127

Pit Gain

1000

2000

3000

0

1000

2000

3000

0

OPEN CLOSED

1/81/4

3/81/25/83/4

7/8SPM

TOTAL STROKES

DRILLPIPE CASING

1500 500

50

66004 bbls.

A. We have circulated more than a bottoms up.B. Pit volume gain is less.

C. DP pressure is constant

E. CP is close to the initial shut in DP pressure.

You have circulated longer. How do you determine it is time to shut it in?

D. Chock is almost all the way open.

128

Pit Gain

1000

2000

3000

0

1000

2000

3000

0

OPEN CLOSED

1/81/4

3/81/25/83/4

7/8SPM

TOTAL STROKES

DRILLPIPE CASING

1500 500

50

66004 bbls.

A. Continue to hold DP constantB. Open choke

C. Close Choke


You have circulated long enough and decided to shut the well in. How do shut down properly?

D. Hold CP constant

129

1000

2000

3000

0

1000

2000

3000

0

OPEN CLOSED

1/81/4

3/81/25/83/4

7/8SPM

TOTAL STROKES

DRILLPIPE CASING

500 500

0

9000

Pit Gain2 bbls.

A. 9.6 PPGB. 10.6 PPG.

C. 9.0 PPG.

D. 10.0 PPG.

E. 8.6 PPG.

You got the well shut-in. What is the calculated Kill Weight Mud that should be pumped?

F. 11.0 PPG.

130

1000

2000

3000

0

1000

2000

3000

0

OPEN CLOSED

1/81/4

3/81/25/83/4

7/8SPM

TOTAL STROKES

DRILLPIPE CASING

1500 500

50

50


C. Close Choke

D. Choke size OK


You bring the pumps back up to Kill Rate Speed, pumping Kill Weight Fluid.Which of the following courses of action would you take?

Pit Gain2 bbls.

F. Shut the well in

131

1000

2000

3000

0

1000

2000

3000

0

OPEN CLOSED

1/81/4

3/81/25/83/4

7/8SPM

TOTAL STROKES

DRILLPIPE CASING

1500 500

50

50

A. 1500 psiB. 1400 psi

C. 1600psi

D. 1000 psi

E. 1200 psi

Everything is going well. You are on the correct gauge and up to kill rate speed. What will the approximate Drillpipe pressure be when kill weight mud reaches the bit?

Pit Gain2 bbls.

F. 1700 psi

132

1000

2000

3000

0

1000

2000

3000

0

OPEN CLOSED

1/81/4

3/81/25/83/4

7/8SPM

TOTAL STROKES

DRILLPIPE CASING

1500 600

50

200


C. Close Choke

D. Choke size OK


The Drillpipe pressure began to drop so you closed the choke slightly. Which of the following courses of action should you take?

Pit Gain2 bbls.

F. Shut the well in

133

1000

2000

3000

0

1000

2000

3000

0

OPEN CLOSED

1/81/4

3/81/25/83/4

7/8SPM

TOTAL STROKES

DRILLPIPE CASING


C. Close Choke

D. Choke size OK


The night cook said that you were wrong and made some adjustments. This is what you see. Which of the following courses of action would you take?

5001200

50

250

Pit Gain2 bbls.

F. Shut the well in

134

1000

2000

3000

0

1000

2000

3000

0

OPEN CLOSED

1/81/4

3/81/25/83/4

7/8SPM

TOTAL STROKES

DRILLPIPE CASING


C. Close Choke

D. Choke size OK


Everything seems to be going well, or is it? Which of the following courses of action would you take?

5001150

50

1400

Pit Gain2 bbls.

F. Shut the well in

135

1000

2000

3000

0

1000

2000

3000

0

OPEN CLOSED

1/81/4

3/81/25/83/4

7/8SPM

TOTAL STROKES

DRILLPIPE CASING

A. DP=0, CP=500, and Pit Gain same.

B. DP=500, CP=500, and Pit Gain = 10 bbls.C. DP=1050, CP=500, and Pit Gain same.D. DP=500, CP=500, and Pit Gain same.E. DP=0, CP=0, and Pit Gain = 10 bbls.

You know that the Drillpipe is full with KW Mud. If you shut down right now,what would your DP, CP and Pit Gain be?

1050 500

50

1600

Pit Gain2 bbls.

F. DP=0, CP=0, and Pit Gain same.

136

1000

2000

3000

0

1000

2000

3000

0

OPEN CLOSED

1/81/4

3/81/25/83/4

7/8SPM

TOTAL STROKES

DRILLPIPE CASING

A. Continue holding Casing pressure constantB. Shut-in

C. Hold DP pressure constantD. Increase Mud weight


You know that the Drillpipe is full with KW Mud. What do you do now? Which of the following courses of action would you take?

1050 500

50

1600

Pit Gain2 bbls.

F. Shut the well in

137

1000

2000

3000

0

1000

2000

3000

0

OPEN CLOSED

1/81/4

3/81/25/83/4

7/8SPM

TOTAL STROKES

DRILLPIPE CASING


C. Close Choke

D. Choke size OK


You made your choice and continued to circulate. This is what you see. Which of the following courses of action would you take?

3500

50

1050 450

Pit Gain2 bbls.

F. Shut the well in

138

1000

2000

3000

0

1000

2000

3000

0

OPEN CLOSED

1/81/4

3/81/25/83/4

7/8SPM

TOTAL STROKES

DRILLPIPE CASING

A. BHP decreasedB. BHP increased

C. BHP did not change

Everything is going so well that you decide to speed things up. You have thedriller bring the pumps up and you keep Drillpipe pressure constant. What happened to BHP?

80

4000

1050 150

Pit Gain2 bbls.

139

1000

2000

3000

0

1000

2000

3000

0

OPEN CLOSED

1/81/4

3/81/25/83/4

7/8SPM

TOTAL STROKES

DRILLPIPE CASING

A. Perform LOT at new MWB. Open annular

C. Close rams

D. Flow check at the choke

The Mud Engineer notified you that KW mud has been coming back for some time. You shut-in and observe the gauges. Which of the following courses of action would you take?

0

8500

0 0

Pit Gain2 bbls.

140


Kicks & Shut-in

Drillers Method



Equipment

Intro

SBM

Special Problems

141

Pressure Lag Time

Measured During Choke Drill at Casing Shoe Before Drilling Ahead

142

PressureLag Time

A change in choke size will create a change in Bottom Hole Pressure (BHP).

Incorrect choke adjustments will lead to incorrect BHP which can allow further influx and/or broken u-tube.

143

Problem in Well Control

Historically Well Control schools taught with the approach that most wells were drilled using a water based mud.

This led to using a rule of thumb that pressure changes traveled at 1 second per One Thousand feet of measured depth on each side of the U-Tube.

144

12,000 ft

145

12,000 ft

0 sec

146

12,000 ft

0 sec

12 sec

147

12,000 ft

0 sec

12 sec

24 sec

148

Problem in Well Control

Recent wells drilled in the GOM, with both surface and subsea stacks have seen Pressure Lag Times (PLT) of 18 sec/7,000’ and 3-4 min./21,000’.

If the “Rule of Thumb” no longer applies then we need to start measuring the PLT.

149

Reasons for Measuring PLT

Mud Typeº Compressibility of Synthetic Fluid

Well Geometryº Deeper Wellsº Larger O.D. >More mud volume

150

Understanding PLT

In the Drillers Method of Well Control, BHP is held constant by manipulating the choke using the proper gauge at surface.

Because the PLT from a choke manipulation to the Drillpipe Pressure Gauge is the longest, it becomes the most difficult to control.

151

Drills

As discussed on Day 1, proper drills are necessary for proper execution.

“Choke Drills” will establish the PLT on your well and allow each choke operator the practice necessary.

152

How do we measure PLT

1. Before drilling out each casing shoe. Trap a small amount of pressure against the choke. Practice proper start- up of the Driller’s Method holding this pressure constant.

2. After moving to the Drillpipe Pressure gauge and allowing the pressures in the well to stabilize, make a definite change on the Casing gauge (50 -100 psi) by opening or closing the choke.

3. Record the time required to see this pressure change reflect on the Drillpipe gauge. This is PLT.

153

1000

2000

3000

0

1000

2000

3000

0

OPEN CLOSED

1/81/4

3/81/25/83/4

7/8SPM

TOTAL STROKES

DRILLPIPE CASING

0

0

300 300

Step 1

Trap some pressure in the well.

154

1000

2000

3000

0

1000

2000

3000

0

OPEN CLOSED

1/81/4

3/81/25/83/4

7/8SPM

TOTAL STROKES

DRILLPIPE CASING

1000 300

50

500

Step 2Bring the pumps to Kill Rate Speed holding Casing Pressure Constant by opening the choke.

After circulation has stabilized, continue pumping holding Drillpipe pressure at 1000 psi.

155

1000

2000

3000

0

1000

2000

3000

0

OPEN CLOSED

1/81/4

3/81/25/83/4

7/8SPM

TOTAL STROKES

DRILLPIPE CASING

1000 400

50

550

Step 3Make a 100 psi choke adjustment and record the time it takes to reflect on the Drillpipe Gauge.

1000

2000

3000

0

1000

2000

3000

0

OPEN CLOSED

1/81/4

3/81/25/83/4

7/8SPM

TOTAL STROKES

DRILLPIPE CASING

1100 400

50

650

It took 100 strokes for the Pressure change to reflect on the DP gauge. At 50 spm this would take 2 min. This is your PLT.

156

1000

2000

3000

0

1000

2000

3000

0

OPEN CLOSED

1/81/4

3/81/25/83/4

7/8SPM

TOTAL STROKES

DRILLPIPE CASING

1000 300

50

500

1st StepDrillersMethod

If you did not conduct a choke drill !

You are at Kill Rate Speed and Drillpipe Pressure is correct.

157

1000

2000

3000

0

1000

2000

3000

0

OPEN CLOSED

1/81/4

3/81/25/83/4

7/8SPM

TOTAL STROKES

DRILLPIPE CASING

900

50

1000

300

The Drillpipe pressure has dropped and I said to keep it at 1000 psi!

What do you do?

A. Close choke slightly monitoring Drillpipe Pressure

B. Close choke slightly monitoring Casing Pressure

C. Do Nothing! Allow the well to balance.

D. Scream “I’m Confused” and tell me to do it myself.

158

1000

2000

3000

0

1000

2000

3000

0

OPEN CLOSED

1/81/4

3/81/25/83/4

7/8SPM

TOTAL STROKES

DRILLPIPE CASING

900

50

1150

300

PLT Got You!

2300

159

TRY AGAIN !!

160

NOT HERE !!

161

1000

2000

3000

0

1000

2000

3000

0

OPEN CLOSED

1/81/4

3/81/25/83/4

7/8SPM

TOTAL STROKES

DRILLPIPE CASING

900

50

1000

400

After closing the choke and watching CP rise by 100 psi you wait,

and wait

and wait

and wait…..

162

1000

2000

3000

0

1000

2000

3000

0

OPEN CLOSED

1/81/4

3/81/25/83/4

7/8SPM

TOTAL STROKES

DRILLPIPE CASING

900

50

1025

400But the DP gauge is still not at the 1000 psi mark. Do you wait some more…

do you pinch in the choke…

or is it time to shut the well in?

163

1000

2000

3000

0

1000

2000

3000

0

OPEN CLOSED

1/81/4

3/81/25/83/4

7/8SPM

TOTAL STROKES

DRILLPIPE CASING

900

50

1050

400

Are you being patient or did you fall asleep?

Surely you have done something by now…. What kind of lag time did you have when you did the choke drill…

Oh! No choke drill……………..

164

1000

2000

3000

0

1000

2000

3000

0

OPEN CLOSED

1/81/4

3/81/25/83/4

7/8SPM

TOTAL STROKES

DRILLPIPE CASING

900

50

1075

400Okay, paints dry.

I feel sorry for the guys still waiting….

Anybody here play golf?

I wonder if I’m underbalanced...

165

1000

2000

3000

0

1000

2000

3000

0

OPEN CLOSED

1/81/4

3/81/25/83/4

7/8SPM

TOTAL STROKES

DRILLPIPE CASING

900

50

1100

400

There is no way it should take this long…

Is that a watch or a sundial on your wrist….

Do you have any idea how much this rig costs per minute!

166

1000

2000

3000

0

1000

2000

3000

0

OPEN CLOSED

1/81/4

3/81/25/83/4

7/8SPM

TOTAL STROKES

DRILLPIPE CASING

900

50

1125

400

Waiting for your relief is not considered a Well Control Method..

Tap the gauge.. Maybe it moved and you missed it….

It’s been more than ten minutes… I think you blew it….

Will it be like this on the simulator ….

167

1000

2000

3000

0

1000

2000

3000

0

OPEN CLOSED

1/81/4

3/81/25/83/4

7/8SPM

TOTAL STROKES

DRILLPIPE CASING

1000

50

1150

300400

Congratulations on your patience. That was three minutes. Can you do this for real!

168

Development of Best Practice

With 95% of our wells using synthetic mud and the geometry of our wells, we are seeing a dramatic affect on our choke handling response during a Driller’s Method Kill.

To get a better understanding of the PLT, we recommend conducting “choke drills” before drilling out the shoe at each casing string.

In order for us to assist you, we need the recorded information from these choke drills so that we may develop some “Best Practices” for handling PLT.

169

Questions or Comments?

170


Kicks & Shut-in

Drillers Method



Equipment

Intro

SBM

Special Problems

171

LEAK-OFF TESTING, WELL DESIGN

and WELL CONTROL

172

Why do we talk about Leak-Off Testing (L.O.T.) and Well Design in a Well Control course, they are “not related”.

That thinking is incorrect. The three are very similar or interrelated.

173

•The U-Tube

All three use the following:

•Pressure

•Boyles Law (P1V1 = P2V2)

•Pore Pressure (formation pressure)

•Fracture Gradients (how strong is the formation)

174

HOW ARE L.O.T.’S , WELL DESIGN AND WELL CONTROL RELATED

We start drilling using a well design with theoretical values for pore pressure and fracture gradients. The L.O.T. gives you the actual fracture gradient, which defines the Maximum Mud Weight that can be used to drill the next hole section.

175

WHY DO A L.O.T. OR F.I.T.

After each casing string is cemented in place, a L.O.T. or F.I.T. should be performed to verify that the casing, cement, and formations below the casing shoe can withstand the predicted wellbore pressures required to get to the next casing shoe.

From a well control point of view it verifies what value our pop-off valve is set at.

176

WHAT IS A L.O.T.

A L.O.T. (Leak-Off Test) is performed by drilling below the shoe 10’ to 50’ of new formation. Close the annular and fracture the exposed formation with your mud. We can now calculate the Frac Gradient and EMW (Equivalent Mud Weight).

177

Total Pressure at the shoe =Hydrostatic + Surface Press.

Fracture Pressure is the TotalPressure that causes the rockto break and split apart.

FRAC PRESS Once the pressure is removedthe overburden will force the rock to close and it regains it’sintegrity until the Fracture Pressis re-applied.

178

WHAT IS A F.I.T.

A F.I.T. (Formation Integrity Test) is performed by drilling below the shoe 10’ to 50’ of new formation. Close the annular and pressure up to a predetermined pressure with your mud. If the formation can withstand the applied pressure, the test is called good. We can now calculate the EMW (Equivalent Mud Weight).

A F.I.T. is similar to pressure testing the cement lines or the BOP.

179

LOT VS. FIT

LOT• Exploration Well• Development well on a

new platform.• Development well in

an old field that has not been drilled in lately.

FIT

• Development well with several other wells in the field.

• Cannot perform a LOT

180

The adoption of a standard leak-off test procedure that specifies the following is recommended.

LOT GUIDELINES

1. Drilling fluid in the wellbore that is of a type and in condition that will freely transmit pressure.

2.Constant injection rates of 1 to 2 barrels per minute.

3.Observation of a stabilized injection pressure for a minimum of 4 minutes.

4.Reading of the surface pressure to be used in the fracture gradient calculation on the casing gauge as per previous procedure.

5.Use of a casing gauge of appropriate range for which accuracy is maintained by scheduled calibrations. (It is recommended that a recording gauge with an accuracy of +/- 2% or better be used).

181

LEAK OFF TEST

2090 psi in 10 sec shut in

10987654321BBL PUMPED

Pump Stopped

0

500

1000

1500

2000

2500

3000

3500

4000

0 2 4 6 8 10 12 14 16 18TIME (MIN)

PRESSURE PSI

Drill Pipe Casing

182

DATA INPUT:Well Name (max 8 characters) Trat A-06Date: 19 Nov. 1998WELL Data:Rotary Table: 106 ft above MSLWater Depth: 240 ftCasing Size: 7 inchCasing Shoe Depth: 10441 ft MDCasing Shoe Vertical Depth: 8232 ft TVDLOT Data:Mud Weight: 11.3 ppg10 sec. Casing Pressure: 2090 psiPump Rate: 1.0 BPM

LOT Data

183

VOLUME PRESSURES (PSI) TIMEBBLS Drillpipe Casing Minutes

0.0 0.0 0.0 0.01.0 262.0 178.0 1.02.0 669.0 600.0 2.03.0 1011.0 942.0 3.04.0 1418.0 1341.0 4.05.0 1901.0 1804.0 5.06.0 2352.0 2239.0 6.07.0 2820.0 2719.0 7.08.0 3335.0 3198.0 8.09.0 2719.0 2513.0 9.010.0 2268.0 2159.0 10.011.0 2276.0 2159.0 11.012.0 2252.0 2127.0 12.013.0 2252.0 2127.0 13.014.0 2207.0 2094.0 14.0

After Stop Pumping14.0 2050.0 2090.0 14.2 (10 sec shut-in)14.0 1945.0 1929.0 15.014.0 1929.0 1901.0 16.014.0 1929.0 1889.0 17.0

184

KICK TOLERANCE AND BOYLES LAW

185

Question:What is our kick tolerance with the shoe at

19,000’ TVD and we want to drill to 25,500’ TVD.

Need to Know - “Kick Tolerance” has 2 components

1. VOLUME (BBLS)

2. INTENSITY (Pressure - Intensity is normally expressed in PPG (Relative to mud weight)

186

• Determine kick tolerance by “picking” a number and then mathematically verifying that the number “picked “ will work or not.

• Mathematical verification is done using Boyle’s Law.

Boyle’s Law: P1V1=P2V2

• AssumptionsAssumptions1) Kick is 100% gas.2) Fluid is WBM - No gas goes into solution.

187

Fracture Pressure at shoe = 14,524 psiBHP = 18,829 psi - (13.6 ppg + .2 ppg + .4 ppg) = 14.2 ppg EMWMW = 13.8 ppg Hydrostatic to shoe = 13,634 psi

25 bbl kick at BHP of 18,829 psi

32.4 bbl when brought to the shoe.

192 ft of gas =192 x 0.1 psi/ft = 19

psi hydrostatic

6,308 ft of 13.8 ppg= 4,527 psi

Gauge Pressure = 18,829 - 4,527 - 19 - 13,634 = 649 psi

649

Pressure at the shoe = 649 + 13,364 = 14,013 psi

14,013

I have not exceeded the Fracture Pressure so the well design would be valid.

If the Fracture Pressure is exceeded- the casing point, kick size and/or intensity would have tobe adjusted and the calculations checked again.

188

P1 = 25,500’ X 0.052 X 14.2 PPG = 18,829 PSI

V1 = Volume (size) of the kick (Arbitrary # based on the size of the kick that can be detected)

V1 = 25 BBLS

The “kick tolerance” that we want to check is 25 BBL. & 0.4 PPG

With TD = 25,500’ TVD

Shoe = 19,000’ TVD *

MW = 13.8 PPG

* If any of these change the kick tolerance changes.

}

189

P1 V1 = P2 V2

P1 = Bottom hole pressure(Pressure of the kick)

Bottom hole pressure = predicted maximum pore pressure + mud overbalance + kick tolerance.

FOR THIS EXAMPLE:• Predicted max pore pressure (at 25,500’ TVD)

= 13.6 PPG EMW• Mud overbalance (for this example it is 0.2 PPG)

= 13.6 + 0.2 = 13.8 PPG• Kick Intensity (Arbitrary number relative to mud

weight) = 13.8 + 0.4 = 14.2 PPG EMW

190

P2 = Weak Link

By design the “Weak Link” is the shoe. The “Weak Link” is defined by the fracture pressure (AKA - Leak Off Test Pressure) of the shoe.

P2 = Fracture pressure of the shoe

= 14.7 PPG EMW (Predicted)

= 14.7 PPG X 19,000’ X 0.052

P2 = 14,524 PSI

V2 = The size of the kick when it gets to the shoe this is unknown. We solve for it.

191

Equation Triangle

P1 x V1

XP2 V2

P1 x V1 XP2 V2=P1 is the pressure that the gas is under.

P1 = BHP

V1 is the size of kickV1 = Barrels

P2 is the pressure of the gas at it’s new position in the well.

P2 = Hydrostatic + Gauge Pressure

V2 is the new size of the kick at it’s new position in the well.

V2 = Barrels

192

Equation Triangle

P1 x V1

XP2 V2

P1 x V1 XP2 V2=

?

P1 = 18,829 psiV1 = 25 bbls

18,829 X 25

P2 = 14,524 psi

14,524

V2 = ?

18,829 X 25 14,524

On your calculator you would key in:• 18,829 x 25 = (470,725) 14,524 =

= 32.4 bbls

193

P1 V1 = P2 V2

V2 = P1 V1

V2 = (18,829 psi X 25 bbl) 14,524 psi

V2 = 32.4 bbls

The 25 BBL kick taken at 25,500’ will have expanded to 32.4 BBL when it is at the shoe at

19,000’.

194

• The maximum pressure that the shoe will see is when the top of the gas bubble (kick) is at the shoe.

• Now that we have the volume of the kick we need to determine the pressure on the shoe.

• If the pressure on the shoe exceeds the fracture pressure then our kick tolerance is too high and must be re-designed.

• What height does the 32.4 Bbl occupy in 14 3/4” hole X 6 5/8” DP - Annulus capacity is 0.1687 bpf

32.4 bbls 0.1687 bpf = 192’

195

CP

Sea bed

.

.

7129’

19,000’/

11,871’ BML

25,500’/

18371’ BML

DPP

Water

HYDROSTATIC PRESSURE (HP)A) 19,000 X 13.8 X 0.052 = 13,634 psi

B) 192’ X 0.1 psi/ft = 19 psi

C) 25,500’ - 192’ - 19,000’ = 6308’

6308’ X 13.8 PPG X 0.052 = 4527 psi

TOTAL HP = A + B + C

= 13,634 + 19 + 4527 = 18180 psi

BHP = HP + Gauge Pressure

or

Casing Gauge = BHP - HP

= 18,829 - 18180

= 649 psi

}c

}B

} A

196

P@shoe = Gauge Press + Hydrostatic@shoe

= 649 + 13,634

= 14,283 psi

Frac Pressure at shoe = 14,524 psi

14,283 < 14,524

Therefore our design is valid and

our “Kick Tolerance”

is greater than 25 BBL and 0.4 PPG so we would be able to tolerate this kick in our design.

197

FRACTURE PRESSURE

LEAK OFF TEST (SHOE TEST)

AND

ROCK FRACTURE GRADIENT

• Both Leak off and rock fracture gradient are

derived from the fracture pressure.

• Leak off pressure is normally reported as PPG EMW.

• Rock Fracture Gradient is normally reported as PSI/FT

198

RKB

MSL

Mudline

92’ Air

7037’ Water

19,000’/ 11,871’ BML

11,871’ Rock

Fracture pressure at 19,000’ TVD = 14,524 psi

A) What is the Leak-off Pressure? =14,524 psi 19,000’ = 0.764 psi/ft

0.764 psi/ft 0.052 = 14.7 PPG

B) What is the rock fracture gradient (FG)?

Fracture Press. = HYD Press water + HYD Press rock

14,524 = (7037’ X 0.447) + (11871 X FG)

14,524 = 3146 + (11,871 X FG)

FG = (14,524 - 3146) 11871 = 0.95 psi/ft

199

• Leak-off pressure is most important to the foreman and drill crews. (Execution)

* This number is a direct indication of what maximum mud weight you can use in this hole section.

• Rock fracture gradient is most important to the engineers. (Design)

* This is an indirect means to compare geology in different areas. It also provides a sound method to compare actual and theoretical (predicted) leak off pressures - answers rock competency question.

200

RKB

MSL

Mudline

92’ Air

7037’ Water

19,000’

11,871’ Rock

Shoe

Frac. Press. = 14,524 psi

LOT Press. = 14,524 psi

19,000’

= .764 psi/ft

= .764psi/ft = 14.7

00.052

Rock Frac Grad. =

14,524 - 7037 X .447 =

11,379 psi

11,379 psi 11,871’ =

0.95 psi/ft

201

RKB

MSL

Mudline

92’ Air

7037’ Water

19,000’

11,871’ Rock

Shoe



19,000’

= .764 psi/ft

= .764psi/ft = 14.7

00.052

Rock Frac Grad. =

14,524 - 7037 X .447 =

11,379 psi

11,379 psi 11,871’ =

0.95 psi/ft

Shoe

RKB

MSL

Mudline

82’ Air

2600’ Water

19,000’

16,316’ Rock



19,000’

= .764 psi/ft

= .764psi/ft = 14.7

00.052

Rock Frac Grad. =

14,524 - 2600 X .447 =

13, 362 psi

13,362 psi 16,316’ =

0.82 psi/ft

202

RKB

MSL

Mudline

92’ Air

7037’ Water

19,000’

11,871’ Rock

Shoe



19,000’

= .764 psi/ft

= .764psi/ft = 14.7

00.052

Rock Frac Grad. =

14,524 - 7037 X .447 =

11,379 psi

11,379 psi 11,871’ =

0.95 psi/ft

Shoe

RKB

MSL

Mudline

82’ Air

2600’ Water

19,000’

16,316’ Rock



19,000’

= .764 psi/ft

= .764psi/ft = 14.7

00.052

Rock Frac Grad. =

14,524 - 2600 X .447 =

13, 362 psi

13,362 psi 16,316’ =

0.82 psi/ft

MSL

Mudline

82’ AirRKB

2600’ Water

19,000’

16,316’ Rock

Shoe



19,000’

= .879 psi/ft

= .879psi/ft = 16.9

00.052

Rock Frac Grad. =

16,697 - 2600 X .447 =

15,534 psi

15,534 psi 16,316’ =

0.95 psi/ft

203

RKB

MSL

Mudline

92’ Air

7037’ Water

19,000’

11,871’ Rock

Shoe



19,000’

= .764 psi/ft

= .764psi/ft = 14.7

00.052

Rock Frac Grad. =

14,524 - 7037 X .447 =

11,379 psi

11,379 psi 11,871’ =

0.95 psi/ft

Shoe

RKB

MSL

Mudline

82’ Air

2600’ Water

19,000’

16,316’ Rock



19,000’

= .764 psi/ft

= .764psi/ft = 14.7

00.052

Rock Frac Grad. =

14,524 - 2600 X .447 =

13, 362 psi

13,362 psi 16,316’ =

0.82 psi/ft

MSL

Mudline

82’ AirRKB

2600’ Water

19,000’

16,316’ Rock

Shoe



19,000’

= .879 psi/ft

= .879psi/ft = 16.9

00.052

Rock Frac Grad. =

16,697 - 2600 X .447 =

15,534 psi

15,534 psi 16,316’ =

0.95 psi/ft

MSL

Mudline

84’ AirRKB

2600’ Water

14,555’

11,871’ Rock

Shoe



14,555’

= .854 psi/ft

= .854psi/ft = 16.4

00.052

Rock Frac Grad. =

12,440 - 2600 X .447 =

11,278 psi

13,362 psi 11,871’ =

0.95 psi/ft

204

SHALLOW LEAK-OFF TEST DRIVES THE WELL DESIGN

205

BS 52#1 GOM 186 1.08 A-19 Cal 393 .9316-2CT Midland 396 1.02A-17 Cal 397 .92Sibual 2-2 Indo 403 1.46YC-2 Indo 414 1.02220 Midland 420 1.18Yakin YC-5HZ Indo 421 1.05201 Midland 424 1.00

Attaka#32 Indo 448 1.00Sakon #1 Thai 495 .92VE 66 #3 GOM 562 .83BA #28 Alaska 582 .94EHI 302 A-13 GOM 679 .89A-20 Cal 681 1.18VE 328 #2 La 681 .81A-19 Cal 755 .93Kham Palai #1Thai 774 1.77BA #28 Alaska 802 .94B-KL-1X Vietnam 814 .94#1-9 Michigan 869 1.71

LEAK-OFF TESTS

WELL NAME WELL NAMELOCATION LOCATIONFRAC DEPTH

FRAC DEPTH

WELL GRAD

WELL GRAD

BELOW IS A VERY SMALL SAMPLING OF OUR MANY THOUSANDS OFL.O.T. STATISTICS

206

INCREASING EXPOSURE

• MORE TIME

• MORE POSSIBILITY OF ENCOUNTERING GAS

LOCATION OF SECOND CASING SHOE(THE KEY TO SHALLOW WELL CONTROL)

FIRST CEMENTED SHOE

SECOND CEMENTED SHOE

DECREASING RESISTANCE TO FRACTURE (PSI)

207

1. Design well to shut-in.

RECOMMENDEDDESIGN / OPERATIONS APPROACH

2. Locate casing shoes in more competent formations.

3. Cement casing.

4. Measure fracture gradients.

5. Use squeezing to guarantee validity of L.O.T.’s Value of fracture pressure Location of fracture

6. Shut in on all kicks at all depths.

208


Kicks & Shut-in

Drillers Method



Equipment

Intro

SBM

Special Problems

209

Definition – any phenomenon, located from mudline to the depth riserless drilling is ended, which puts a wellbore, location, or structure at risk.The hazard may be natural or man made.

Shallow Hazards

210

Pipelines and man made structures

Shallow Hazard Examples

Unstable Seafloor: faults, slumps, and channels

Gas vents and mud volcanoes

Hydrates (“Primary and Secondary”)

Chemosynthetic Communities

Subsurface water, gas and sediment flows (SWF)

211

Gas Hydrates are ice-like crystalline solids (minerals) in which hydrocarbon and non-hydrocarbon gases are held within rigid cages of water molecules.

Gas Hydrates

212

Form at high pressures and low temperatures 40 degrees F and 780 psia

* Sloan 1998

Hydrate Formation

Commonly found in water depths of 1200’ - 6000’ (deeper sites not well sampled)

Usually associated with some type of gas vent

Modeling has indicated hydrates may exist as deep as 3000’ BML on GOM slope*

213

Unstable sea floor if hydrates are melted Chemosynthetic Communities / Hardgrounds Unstable wellbore associated with primary

hydrates “Secondary” Hydrate accumulation on subsea

equipment. (Associated with SWFs not primary hydrates)

Hydrate Hazards

214

Kutai Basin, Indonesia Hydrate X-Section

Hydrates

215

GR RES

HydratesInterval

WD : 5312’

5635’

-5987’

Nakula #1, Kutai Basin, Indonesia (Near Seno Field)

Subsurface Hydrates

216

Water depths > 3000’, Mudline temp ~ 40o F Encountered between 0 - 600’ BML Seismic character high amplitude events Log character high resistivity zones Increase in ROP Flows noted while reaming with seawater Borehole swelling (could not get casing down)

Hydrate Characteristics Kutai Basin, Indonesia

217

Initial drilling riserless with Seawater

Displace with 9.8ppg WBM and pull out of hole

If tight spots noted across from Hydrates begin back reaming with 9.8ppg WBM.

If back reaming becomes problematic switch to seawater and re-ream the hole to bottom.

Displace with 9.8ppg WBM mud and spot 18ppg floating mud cap across hydrate zone to ML.

* Glen Olivera Drilling Superintendent Unocal Indonesia

Hydrate Drilling SOP Indonesia*

218

Any flow of water and/or gas into the wellbore, in flow paths around the annulus or to the seafloor. SWFs have been reported in water depths of 500 - 7,000 feet and observed between the mudline and 4000’ below mudline (BML). Typically problems arise between 950 and 2000 feet BML.

Shallow Water Flows (SWF)

219From paper by Pelletier 1999 SWF Forum

Overpressure Mechanisms

220

Overpressure Mechanisms

• Remember the sponges

and

• Charged formation

221

Uncontrolled Water Flows

Sediment washout (cement integrity)

Sediment Compaction

Casing Collapse and Buckling

Formation of seafloor craters, mounds and cracks

Problems Associated with SWFs

222

ERWE-19 WELL-SEC

Prog.@-732’ SSD of top gas sand

Prog.@-902’ SSD of top gas sand

Water Depth = 198’ SSD

Final Depth-923’ SSD

Tw

o-w

ay ti

me

ms.

Dep

th (F

t. SS

.)

223

224

Unocal DeepwaterShallow Hazard Assessment

Geology

Geophysics

Drilling

Petrophysics

Integrated Team Work

225

Geomechanics

Overburden Assessment

Fracture Gradient Prediction

Pore Pressure Prediction

Offset and Regional Mud and LOT data

Real Time analysis with PWD and ROV

226

BEST PRACTICES - PART 1

Site Assessments to start early in prospect life. Multi-discipline cross functional team involved Third party analysis of hazards is not enough Pick locations with shallow hazards in mind

– Depth – Thickness– Geologic setting– Presence/absence of sandstone– Presence/absence of a pressure seal – Presence/absence of hydrocarbons

227

BEST PRACTICES - PART 2

Wherever possible move locations to avoid potential hazards

If hazard can not be avoided, mitigate risk– map interval & specific horizons– radial seismic panels– pressure prediction– revise well design

Set 36” casing deep enough to allow control of shallow hazards with weighted mud.

Utilize “UCL Riserless Drilling Procedure” to minimize probability of a flow occurring.

228

BEST PRACTICES - PART 3 If flow occurs kill well immediately

– Problems worsen with time– Assess situation before resuming drilling operations

Riserless drilling “stops” when a 10 PPG leak-off can be reasonably expected.

Pump out of hole with “good quality” kill weight mud

Run 20” casing as per “UCL Riserless Drilling Procedure”

Use Cementing Best practices– Foam cement– Centralized casing

229

CONCLUSIONS

Unocal has made significant improvement with regards to shallow hazard identification

Shallow Hazard identification requires considerable time & focused effort

Unocal’s well design and well execution capabilities have enabled us to drill potential shallow hazards with a high degree of success

Fully integrated multi-disciplined team approach to shallow hazard identification is paying off

230

First Hole Section- Riser or Riserless?

231


Kicks & Shut-in

Drillers Method



Equipment

Intro

SBM

Special Problems

232

2500’

4000’

CERVEZA - 1983• Diverted• 2 - 8” lines• Diverter Failed• Fire• No Breach

$35 Million

456’

1225’

ATTAKA J1 - 1981• Diverter Failed• Fire

5 FatalitiesMultiple Injuries

GRAYLING - 1985• Diverted• 1 - 4” line• Diverter Failed• No Fire• Breached

$40 Million

420’

3565’

766’

2265’

STEELHEAD - 1987• Diverted•2 - 10” lines• Diverter Failed• Fire• Breached

$150 Million (Operated by Marathon)

SHALLOW GAS KICKS 1980-1989

233

Attaka 38a - 1998• Gas in water• Evacuated Rig• Flow stopped on its own

No InjuriesMinimal Cost

460’

SHALLOW GAS KICKS 1990 - 2000

500’

Attaka 38 - 1998• Gas in water• Moved rig off location• Flow stopped on its own


B-TXT-2X - 2000• Gas in water• Evacuated Rig• Flow stopped on its own


915’ 509’

2755’

Molavia Bazar - 1997• Diverter system failed• Fire• Breached

•$10+ Million (Operated by Oxy)

234

DIVERTERS

Gas/Sand mixtures flowing through diverter lines have been measured to erode through steel at the rate of 8” per hour.

NO RELIABLE MEANS EXISTS TO ELIMINATE THIS PROBLEM!

Use of a diverter does not lead to control of a well. These devices may be required where no better alternative exists for handling flow from shallow holes, but their use should be limited to improving the conditions during which evacuation takes place.In short ---

DIVERT AND DESERT !

235

Well Control Equipment

Checklist: Well Control Equipment

Check temperature rating for elastomers, particularlyin variable bore rams. If shear rams are installed, ensure that the shear rams can, in fact, shearall grades of drill pipe in use.

One of the critical aspects in planning a well is the theoretical maximum surface pressure to be used in designing the casing, wellhead, bop stack, choke manifold,gas buster, testing, and other equipment.

236

ANNULAR

BLINDRAMS

PIPERAMS

PIPERAMS

TO CHOKE LINETO KILL LINE

WELLHEAD

BOP CONSIDERATIONS

237


Accumulators ‑ Should have sufficient volume to close and hold closed all preventers and maintain accumulator pressure above minimum system pressure.

238

USEABLE FLUIDTo provide energy, the bladder is pre-charged to 1000 psi with Nitrogen.To provide closing fluid, it must be pumped into the bottle

1000

10 galN2

239

Equation Triangle

P1 x V1

XP2 V2

P1 x V1 XP2 V2=

?

P1 = 1000 psiV1 = 10 gal

1000 X 10

P2 = 1200 psi

1200

V2 = ?

1000 X 10 1200

On your calculator you would key in: 1000 x 10 = (10,000) 1200 =

= 8.3 gal of Nitrogen

10 - 8.3 = 1.7 gal of fluid

240

USEABLE FLUIDIt takes 1.7 gallons of fluid to compress the Nitrogen to the Minimum System Pressure of 1200 psi.

1000

10 galN2

1.7 galFluid

1200

8.3 galN2

241

Equation Triangle

P1 x V1

XP2 V2

P1 x V1 XP2 V2=

?

P1 = 1000 psiV1 = 10 gal

1000 X 10

P2 = 3000 psi

3000

V2 = ?

1000 X 10 3000

On your calculator you would key in: 1000 x 10 = (10,000) 3000 =

= 3.3 gal of Nitrogen

10 - 3.3 = 6.7 gal of fluid

242

USEABLE FLUIDTo get useable fluid, I must continue to pump fluid until I reach the Operating Pressure of 3000 psi.It takes a total of 6.7 gallons of fluid to compress the Nitrogen to 3000 psi.

1.7 galFluid

1200

8.3 galN2

6.7 galFluid

3000

3.3 galN2

• The volume of fluid it takes to change the pressure from Minimum System Pressure to Operating Pressure is the useable Fluid per bottle. (6.7 - 1.6 = 5 gallons/bottle)

UseableFluid

243

Accumulator Volume

AtmosphericPressure

3000

psi

18 gal. to close

7 gal. To close

7 gal. To close

6 gal. To close

Total gallons to close = 39 gallons

39 gal. X 1.5 safety factor = 59 gal. Of useable fluid required59 gal. X 2 = 118 gal. Of total stored fluid118 10 = 11.8 or 12 bottles

1 gal. To open

244


High Pressure Flexible Hoses ‑ Confirm that flexible hoses are acceptable for exposure to unusual fluids which may be encountered or used and meet acceptable temperature ranges.

245


Bleed‑Off Valve & Line ‑ The bleed‑off valve and line allow flow directly from the choke manifold to the overboard line or burner boom to protect the mud/gas separator from being overloaded.

246

Low Temperature Problems

All equipment, which may be exposed to wellbore fluid downstream of the choke, should be designed to withstand the low temperatures resulting from gas expansion during well control procedures.

Critical guidelines on choke manifold acceptance and maintenance is important. Periodic checks should be conducted to check the thickness of piping and manifolds.

247


Mud/Gas Separator ‑ Pressure gauge on the separator body should be installed to ensure that the separator is operating within its rated capacity and no gas is being allowed to "blow through" to the mud processing areas. Thoroughly inspect the separator structural integrity and internal condition.

248

GAS BUSTER

GAS

Baffle PlatesImpingement Plate

Siphon Breaker

Drain Line With Valve

From Choke

Pressure Gauge

• Diameter & length of ventline controls amount of pressure in separator

• Height, Diameter & Internal design controlsseparation efficiency

Vent LineNO VALVES!

• Height of “U” tube (D) & distance from bottom of separator to top of “U” tube (d) controls fluid level in separator and keeps gas from going to flowline

d

D

To Mud DegasserNO VALVES!

Inspection Cover

249


Additional Considerations ‑ The compatibility of elastomers with drilling, completion, & testing fluids should be checked. The collapse rating of the drill string should be checked against collapse load during a well control operation. The most severe load is frequently found at the closed pipe rams.

250

BOP TESTINGRECOMMENDED FIELD TESTS:

Low HighRam Preventers 200-300 psi WP or CSG. BurstAnnular Preventers “ 70% WP

Ram and Annular preventers are “Wellbore Assisted.” This means that pressure from the well helps to energise the elements and seal off the well. This is why low pressure tests are sometimes harder to achieve.

Bumping the pressure up to get a seal and then bleeding off to get the test is dangerous. How many 5,000 psi vs. 300 psi kicks do we take?

251


Kicks & Shut-in

Drillers Method



Equipment

Intro

SBM

Special Problems

252

SBM OBM

Gas Kicks: migration, solubility. Ballooning;

253

Myths about Synthetic and Oil Base Muds

Gas kicks do not migrate.

Gas kicks do not cause volume change.

Gas kicks come out of solution all at once.

Gas kicks come out of solution slowly.

254

Facts about Synthetic Base and Oil Base Muds

Gas migrates in SBM / OBM until it goes into solution.

Gas in solution may have one half the volume as does gaseous gas.

Gas enters the wellbore at full volume.

Gas come out of solution at rates depending on temperature, pressure and concentration.

255

Solubility vol/vol

-1000

0

1000

2000

3000

4000

5000

6000

0 200 400 600

PressureWestNorth

256

Boyle’s Law

• P1 x V1 = Constant

• P1 x V1 = Constant = P2 x V2

Any point in the well

Known information

257

Boyle’s Law (continued)

10,000’10 bbl

5,000’

11.0ppg MW

11 x 00.052 x 10,000 = 5,720 psi

P2 = ?2,860 psi

V2 = P1 x V1 ÷ P2 = ?20 bbl

258

Pressure / TemperatureEffect on Density

Temperature(F)

Pressure(psig)

MeasuredDensity

( lbm/gal)78 0 17.000

3,000 17.1456,000 17.2759,000 17.389

12,000 17.49215,000 17.589

200 0 16.3923,000 16.5926,000 16.7609,000 16.905

12,000 17.03315,000 17.149

350 3,000 15.8906,000 16.1229,000 16.310

12,000 16.46915,000 16.608

This table shows laboratory resultson a 17 ppg mineral-oil based mud.

259

Kick Detection

• Kick detection is more difficult when oil/synthetic base drilling fluid is used over a water base drilling fluid because gas is soluble in the OBM/SBM.

• However, gas cannot enter the wellbore without causing some changes in fluid volume .

• Therefore, it is concluded that an increase in flow and/or pitgain is the most reliable indicator of a kick during drilling in either OBM/SBM or WBM.

The perception that gas kicks totally “hide” in OBM / SBM is false. The gain is there but our ability to measure that gain depends on accurate, working PVT’s and flow shows, good pit discipline and alert Drillers and Mud Loggers.

260

Volume At Surface

12.4 ppg SBM The well unloaded 30 bbls at Bottoms Up.

6” Open Hole to TD@12,000

• P1 = 14.7 psi• V1 = 30 bbls• P2 = 12.4 x 0.052 x 12,000 = 7,740 psi• V2 = .057 bbl kick on Bottom (no solubility)• V2 = .03 bbl Kick on Bottom (50% solubility)

Can you detect this size kick?

261

Bubble Point

• The gas oil ratio (GOR) is a measure of the amount of gas that is mixed with a given volume of oil.

• The higher the GOR the deeper in the well the gas begins to break out.

• As some of the gas breaks out it lowers the GOR of the remaining influx.

The remaining influx is then circulated further up the hole until it reaches the new “bubble point” at which time some of the gas breaks out, again lowering the GOR in the remaining influx.

• This cycle is repeated till all of the gas has become free gas.

262

Bubble Point

• If the well is circulated with the BOP’s open, the gas is able to come out of solution quickly. This can result in mud being pushed above the bushings.

• If the well is being circulated through the choke, the backpressure helps keep the gas in solution and protects the rig and it’s crews.

263

Bubble Point

• At any time that you suspect that you have taken a gas influx, or that it is possible that you have taken a gas influx, circulate the well with the last 2000+ ft. circulated across the choke.

264

General Trends With Gas Solubility

The OBM/SBM composition has a dramatic effect on gas solubility. Assuming that gas is insoluble in water, as the amount of brine or water and emulsifiers increase then the solubility of the gas in the mud system decreases.

As the amount of solids increase, the solubility of the gas decreases.

As temperature increases, gas solubility decreases.

As the gas specific gravity increases gas solubility decreases.

As pressure increases gas solubility increases.

265

Ballooning / Micro Fracturing

266

Connection Flow Monitor - Breathing

-10

10

30

50

70

90

110

130

150

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17

Time, min.

Cha

nge

Pit V

ol.,

bble

Feb. 14, 80 bbl.No breathing

Feb. 15, 112 bbl.Breathing

Feb. 14, 142 bbl.Breathing

267

Connection Flow Monitor - Flowing

-10

10

30

50

70

90

110

130

150

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17

Time, min.

Cha

nge

Pit V

ol.,

bble

Jan. 10, start of interval, 100 bbls.No breathing

Point of infelction

Jan.. 12, well flowing, 140 + bbls

268

269


Kicks & Shut-in

Drillers Method



Equipment

Intro

SBM

Special Problems

270

GAS INFLUX / MIGRATION AFTER CEMENTING

Gas may enter well after cementing due to temporary reduction in annulus pressure as cement begins to set, resulting in a kick.Observe the well after cementing and be ready to shut well in if annular flow occurs.To reduce the likelihood of this problem, the following cementing practices have been shown to be helpful:

• Condition mud well before cementing.

• Use a well designed spacer/wash ahead of the cement to assist in mud removal.

• Centralize the casing in the wellbore.• Maintain turbulent flow while cementing.• Move the casing while cementing.

No technique to date has been 100% successful in eliminating this problem - Remain Alert!

• Fast Transition Time- Right set cement

271

ABANDONING A “DEAD” WELL

Air

Oil

WaterProducing Zone

Heavy Fluid

Air

272

ABANDONING A “DEAD” WELL

There are very few “DEAD” wells.

Remain ALERT at ALL times

Use the trip tank when ever possible

Keep good pit Discipline

273

BROKEN U-TUBES

This requires a high rate oflosses. Slight losses can bedealt with during the regularDrillers Method.

274

RECOGNIZING BROKEN U-TUBES

• A sudden break back in surface pressures

• Fluctuations in casing pressure

• Loss of communication between drillpipe & annulus

• Drillpipe pressure decreasing or on vacuum

• Sudden vibration in drillpipe, BOP, and/or tree

• Fluctuations in drillpipe pressure

• Numerous choke changes

275

REPAIRING BROKEN U-TUBES

• Analyze and think

• Try slowing down first - ECD’s may be to high.

• Must fix from the top down.

• Temporarily shut off bottom.

276

COMMON CONTROL METHODS

Most of the attempts to control an Underground

Blowout (complete losses) are hit or miss.

Instead of analyzing the well to define the real

problem, assumptions are made and one of the

following solutions is begun. If this doesn’t work

you try something else.

277

COMMON CONTROL METHODS• Pumping LCM, gunk or cement to the loss zone in an attempt to regain

conventional control.

• Bullheading kill fluids into the loss and/or producing zones.

• A Dynamic kill using frictional pressure loss and fluid density to increase wellbore pressure opposite the producing zone.

• A Bottom Kill (weighted slug below the loss zone to overbalance the producing zone).

• A “sandwich kill” that bullheads kill fluid from both above and below the loss zone.

• A barite pill or cement plug to bridge and isolate the producing zone from the loss zone.

• A bridge plug set to isolate the producing zone from the loss zone, or more commonly just to provide a subsurface closure while surface equipment is changed or pipe is run in the well.

278

COMMON CONTROL METHODS

• Knowledge of the location, pressure, and flow characteristics of the producing and loss zones and the flow path

To improve your chance of success with the previous methods, formulate a strategy that includes;

• Definition of a kill approach and a sequence of steps that will achieve the ultimate objective

• Confirmed information on fluid properties, densities, volumes, placement and rates necessary

• Access to the necessary people, equipment, materials and instrumentation to implement the strategy

• Checkpoints, usually pressures, that allow you to monitor your progress and/or success

• An agreed upon basis for stopping the operation, analyzing and changing the operation if your plan is not progressing as predicted.

279

MECHANICAL COMPLICATIONS

COMPLICATION DPGAUGE

CPGAUGE

PLUGGED JET NO CHANGE

PLUGGED CHOKE

WASHED CHOKE

LOSINGCIRCULATION

WILL FOLLOW CPWITH SMALLER

SWINGS

ERRATICFLUCTUATING

HOLE INWORKSTRING

NO CHANGE

HOLE PACKEDOFF

= HAPPENS FIRST = HAPPENS AFTER TIME LAG

280

INTACT U-TUBE

DRILLERSMETHOD

DPGAUGE

CPGAUGE

PITGAIN

CHOKEDIRECTION

CLEARINFLUX

KEEPCONSTANT

SLOWLYINCREASING

INCREASINGTHEN BACK

TO ORIGINAL

MOSTLYOPENING

KWF TOBIT

DECREASING KEEPCONSTANT

CONSTANT NOCHANGE

KWF TOSURFACE

KEEPCONSTANT

SLOWLYDECREASING

CONSTANT MOSTLYOPENING

281

W E L L C O N T R O L L O GT I M E D P

P S IC A S I N G

P S IC H O K E

S I Z ES T R O K E S P I T

G A I NC O M M E N T S

282

ORGANIZING & DIRECTING IN WELL CONTROL

Value of Rig Crew Drills - TEAMWORK

• Keeps possibility of kick control in minds of crew and supervisors (like school).

• Causes drilling foreman to plan ahead of time how he will organize and direct.

• Make assignments for circulating-out kick the last step in shut-in drills.

• Gets everyone familiar with the equipment on the rig and get more comfortable with the procedures.

283

ORGANIZING & DIRECTING IN WELL CONTROL

Foreman Should Be At Critical Spot While Kick Is Being Circulated Out

• Needs to be free to move around as much as possible.

• Will depend on competence of contractor people (toolpusher and driller, particularly).

• Hopefully not running the choke, but should be observing choke operations until a certain point.

• When is that point? Driller’s Method: Bringing pumps up & down, changing gauges.W & W Method: Bringing pumps up & down, until KWM to bit.

284

Formulas1 Phydrostatic = MWppg x .052 x TVDft

2 MWppg = Pressurepsi .052 TVDft

3 TVDft = Pressurepsi .052 MWppg

4 Gradientpsi/ft = MWppg x .052

5 Gradientpsi/ft = Pressurepsi TVDft

6 MWppg = Gradientpsi/ ft .052

7 Capacitybbl/ft = Hole Diameter2 1029.4

8 Annular Capacitybbl/ft = (Hole diameter2 - Pipe Diameter2) 1029.4

9 Fluid Column Heightft = Volumebbls Capacitybbl/ft

285

1 Displacementbbl/ft = Pipe Weightlbs x .00036

2 Triplex Pump Outputbbl/stk = .000243 x Liner Diameterin2 x Stroke Lengthin x Efficiency%

3 Total Pump Strokes = Volumebbls Pump Outputbbl/stk

4 Kill Weight Mudppg = (SIDPPpsi .052 TVDft) + MWppg

5 Volume of Slugbbls = Mud Weight.ppg x Dry Pipe Lengthft x Pipe Capacitybbl/ft

Slug Weightppg - Mud Weightppg

6 Slug Weightppg = Mud Weightppg + Mud Weight.ppg x Dry Pipe Lengthft x Pipe Capacitybbl/ft

Slug Volumebbls

7 Pit Gain from Slugbbls = Volume of Slugbbls x Slug Weightppg - Mud Weightppg

Mud Weightppg

8 Depth Slug Fallsft = Pit Gain from Slugbbls Pipe Capacitybbl/ft

9 Pump Pressure Correction: For Mud Weight ChangeFor Mud Weight Change- New Pump Pressurepsi = Original Pressurepsi x (New Mud Weightppg Old Mud Weightppg)

For Pump Speed ChangeFor Pump Speed Change-New Pump Pressurepsi = Original Pressurepsi x (New SPM Old SPM)2

Formulas

286

Contact InformationRick Dolan:[email protected]

George Grundt:[email protected]

Benny Mason:[email protected]

Documents

Drilling Basic 2001 Manual