Drilling Basic 2001 Manual

DRILLING

BASIC TRAINING MANUAL

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

1

Intro Pressure Basics (The U-Tube) Kicks & Shut-in Drillers Method Gauge Questions Pressure Lag Time LOT & Well Design Shallow Hazards Equipment SBM

Special Problems

2

Drilling Basic Table Of Contents

• • • • • • • • • • • •

SECTION

SLIDE

Introduction Pressure Basics U-Tube Boyles Law / Inversion ECD Surge / Swab Pressure Kicks Cause & Detection Shut-In Drills Drillers Method Kill Weight Mud Other Well Control Methods

2-11 12-27 28-35 36-43 44-45 46-50 51-59 60-62 63-66 67-103 104-105 106-109

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 3

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

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

George Grundt - (281) 287-7254 - [email protected] 4

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

5

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 6

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.

7

OTHER IMPORTANT DETAILS Emergency Exits No Smoking Restrooms Mobile Phones/Beepers Daily Start - Exactly @ 8 AM Daily End - Approximately 4:30 PM Lunch

Breaks 8

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. 9

WHY WE ARE HERE The 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. 10

Communications 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.

11


Special Problems

12

Well Control

With 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.

0psi

0psi

Hydrostatic = 5000 psi


BHP = 5000 psi

13

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

1 lb

1 lb

1 3 2 0

1 lb

lb 14

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

Force Area

1 lb

=

3 lbs = 3 psi 1 sq. in.

1 lb 1”

1 3 2 0

1”

lb 15

Pressure In our industry, when we are measuring pressure it is usually pressure created with 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)

PSIhydrostatic = Fluid Weightppg x 0.052 x Vertical Height of fluid

1’ 1”

1”

Weight of 0 lb Fluid

16

12” 12”

What is 0.052? 1”

1”

1 ft. = 0.052 gal. 12”

12” X 12” = 144 in2

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. 17

Gradient 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?

1”

1”

10ppg x 0.052gal/sq. in./ft = Pressureft 10 x 0.052 = .52 psift 1 ft. = 0.052 gal.

This means that for every foot of mud in the well, the pressure increases by .52 psi. So, Gradientpsi/ft x TVDft = Pressurehydrostatic 18

TVD vs MD Because 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.

10’ 11’

19

Pressure Equations •Hydrostatic Pressure (psi) = MW (ppg) X 0.052 X Depth (ft) HP = PPG X 0.052 X TVD •Hydrostatic Pressure (psi) = Gradient (psi/ft) X Depth (ft.) HP = G X TVD •Gradient (psi/ft) = Fluid Weight (ppg) X 0.052 G = MW X 0.052 •Equivalent Mud Weight (ppg) = Gradient (psi/ft) ÷ 0.052 EMW = 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 20

Equation Triangle Pressurepsi = MWppg X 0.052 X TVDft

Pressurepsi

MWppg X 0.052

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

X TVDft 21

Equation Triangle If you want to solve for MW or TVD, fill in the known information and the equation is written for you. 1) SIDPP is 500 psi. Hole TVD is 11,000 ft. How much MW increase is needed to kill the well?

.87 _______ppg Pressure 500 psipsi

500 psi

MWppg = 0.052 x11000 ft MWppg =

MW TVDft ft ? ppg X 0.052 X 11000

500 572

On your calculator you would key in: • 0.052 x 11000 = 572 • 500 ÷ 572 = .87ppg 22

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

Pressure 100psi psi

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 200

FT =

100 psi 9.6ppg x 0.052

FT =

? ft MW 9.6ppg 0.052 X TVD ppg X 0.052

100 .5

On your calculator you would key in: • 9.6 x 0.052 = .5 psi/ft • 100 ÷ .5 = 200ft 23

FORMATION PRESSURES 8.4 ppg > Normal Pressured formations < 8.9 ppg Abnormal Pressured formations > 8.9 ppg 8.4 ppg > Subnormal Pressured formations As 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 cannot escape and becomes pressurized by the weight of the sponges above. If you make a hole in the bottom sponge:

24

FORMATION PRESSURES Normal, Abnormal & Subnormal 8,000’ 4,500 ÷ 8,000 = .56 psi/ft .56 ÷ 0.052 = 10.8 ppg

B

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

A

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

form atio n

=4

500 psi 25

CHARGED SANDS

COMMUNICATION TO SURFACE CAN BE HARMFUL TO YOUR WELL BEING!

Poor cement practices can lead to communication outside the casing.

26

Up Structure Locations-Normally Pressured Fields WELL B

WELL A

WELL C

WELL D

“NORMAL” GRADIENT ALL ZONES

3600’

D C

3900’

S GA

4000’ 4100’

E AL H S

A

ND SA

E AL H S

B

GAS/ WATER CONTACT

PD= PC= PB= 1860 psi G = 1860 / 3600ft = .517 psi/ft MW D = 9.9 ppg

PC = PB= 1860 psi G = 1860 / 3900ft = .477 psi/ft PB = 4000’ x .465 psi/ft = 1860 psi PA = 4100’ x .465 psi/ft = 1906 psi

MW C = 9.2 ppg

MW b = 8.9 ppg MW a = 8.9 ppg

27

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

The workstring and the annulus form our u-tube.

10,000 ft

The gauge should be Bottom Hole Pressure.

28

U- Tube 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

29

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

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

5

= 9.6ppg x 0.052 x 10ft

30

U- Tube Calculate Bottom Hole Pressure

Practice

AIR

1,500 ft of 13.6 ppg

10.2 ppg

4,000 ft of 10.2 ppg

6000 ft

6000 ft TVD 31

U- Tube Calculate Bottom Hole Pressure

Practice

1,000 ft of 10 ppg

5,500 ft of 10 ppg

5,000 ft of 9.6 ppg

6000 ft

500 ft of 6 ppg 6000 ft TVD 32

U- Tube Calculate how far the slug has dropped.

Practice

1,200 ft of 12 ppg

6,000 ft of 10.5 ppg

6000 ft

6000 ft TVD 33

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

U- Tube Practice

= Gauge Press.

6,000 ft of 10 ppg fluid

6,000 ft of 12.5 ppg

6000 ft

BHP =

6000 ft TVD 34

Well Control

Remember: 0psi

780psi



BHP = 3900 psi

35

Uncontrolled Expansion

MUD

0’

600-1200’ LONG

500’

40’ LONG

1000’

20’ LONG

1500’

13.5’ LONG

2000’

10 LONG

36

GAS EXPANSION V2 = (P1 X V1) ÷ P2 P1 = 5000 psi V1 = 10 bbls Hydrostatic = (9.6 X 0.052) X 10,000 = 5000 psi

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

? bbls Gas Top of gas at 5000 ft.

2500 psi P2 = Where? 20bbls bbls V2 = ?

10 bbls gas New Hydrostatic (9.6 X 0.052) X 1000 = 500 psi

P = 500 Where? psi ? bbls Gas 22 ? bbls bbls Top of gas V22 = 100 at 1000 ft.

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

? bbls Gas Top of gas P2 = 500 Where? psi at 100 ft. ? bblsbbls V2 = 1000 37

Equation Triangle P1 x V1 = P2 X V2 P1 is the pressure that the gas is under. P1 = BHP V1 is the size of kick V1 = Barrels P2 is the pressure of the gas at it’s new position in the well.

P1 x V1

P2 = Hydrostatic + Gauge Pressure

P2

X

V2

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

38

Equation Triangle P1 x V1 = P2 X V2 P1 = 5000 psi V1 = 10 bbls P2 = 14.7 psi V2 = ?

5000 P1 x X V110

5000 X 10 14.7

= 3,401 bbls

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

P2 14.7

X

V?2 39

Volume At Surface • 12.4 ppg WBM • The well unloaded 30 bbls at Bottoms Up.

• 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?

6” Open Hole to TD@12,000

40

PRESSURE INVERSION 250

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

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

250 Gauge Press. + 4930 Hydrostatic 5180 psi Gas Press. 143 ft

41

PRESSURE INVERSION 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

5180

143 ft Hydrostatic = (5000 – 143) X 0.052 X 9.6 = 2430 psi 42

PRESSURE INVERSION 5180 143 ft

5180

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

Hydrostatic = (10000 – 143) X 0.052 X 9.6 = 4921 psi 5180 Gas Press. + 4921 Hydrostatic 10,101 psi Bottom Hole 43

ECD

2300

SPM = 100

Hydrostatic = 10 X 10,000 X 0.052 = 5,200 psi Circulating BHP = 5,200 + 115 Friction loss = 5,315 psi in surface lines = 150 psi

Mud Weight = 10 ppg

Annular Open

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

2150 0

Drillstring friction loss = 745 psi

Friction loss at bit = 1290 psi

Annular friction loss (AFL) = 115 psi

115

1405 TVD = 10,000 ft

44

ECD

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

Reverse Circulate

Circulating BHP = 5,200 + 2,035 = 7,235 psi ECD = 7,235 ÷ 10,000 ÷ 0.052 = 13.91 ppg

2300

Mud Weight = 10 ppg SPM = 100 Annular Closed Friction loss in surface lines = 150 psi

0

2150

Drillstring friction loss = 745 psi

Friction loss at bit = 1290 psi

Annular friction loss (AFL) = 115 psi

2035

745 TVD = 10,000 ft

45

Swab Pressure In a static condition, Bottom hole pressure is equal to Hydrostatic Pressure. As the pipe is pulled out of the hole, friction creates a swab pressure that is felt upward. 10 ppg

Swab Pressure

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

46

Swab Pressure If the swab pressure is greater than the overbalance, fluid in the formation can enter the well. In this example, the swab pressure created is 50 psi more than the overbalance. This would let formation fluid into the well.

10 ppg

Swab Pressure = 150 psi

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

47

Swab Pressure When the pipe movement is stopped, the friction is lost, and the overbalance is returned. Even though the overbalance is restored, the fluid that was swabbed in is still in the well.

10 ppg

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!!

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

48

Swab Pressure

Factors that create swab pressure are: • Clearance • Yield Point of mud

10 ppg

• Pulling Speed of Pipe • Length of Drillstring

49

10,000 ft

Surge Pressure 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. 10 ppg

Factors that create surge pressure are: • Clearance • Yield Point of mud • Running Speed of Pipe • Length of Drillstring High surge pressure can cause the formations to fracture and lost circulation to occur. Surge Pressure = 150 psi 50

10,000 ft


Special Problems

51

TRENDS IN KICK DECTECTION, JUST LIKE DRILLING • What are the trends • How do you recognize the trends • Teamwork • Think and react 52

Kicks Cause THE MAIN CONDITION THAT ALLOWS A KICK TO OCCUR: THE PRESSURE IN THE WELL BORE BECOMES LESS THAN THE PRESSURE IN THE FORMATION

53

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 with mud weight too low.

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

3. Drilling into an unexpected abnormal formation pressure.

Careful engineering;proper well design;Understand the Geology; Use Pressure Hunting Techniques STUDY OFFSET WELLS!

54

Decreasing Occurrence 4. Lost Circulation (Fluid level, not rate of loss is critical in well control.) 5. Unloading mud by pulling balled drilling assembly.

Careful engineering; proper well design;Understand the Geology CASE OFF LOST CIRC. ASAP!

Measurement of fill-up volume when pulling drill string. TRIP TANK!

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

Measurement of fill-up volume when pulling drill string. TRIP TANK! 55

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% 56

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%

57

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

58

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. 59

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. 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.

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 60

SHUT-IN PROCEDURE WHILE 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”) AND Open HCR valve. 5. Toolpusher and Drilling Foreman on floor. 6. Put on Top Drive and open safety valve. 7. Read/record gain in pit volume. 8. Start moving pipe if reasonable. 9. Read/record gain in pit volume.

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. 61

ROLES & RESPONSIBLITIES Drilling 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.

62

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. 63

KICK DRILL Pit Drill/Flow Drill Action Initiate Drill Lift flow sensor or Pit float to indicate “kick” Immediately record start time.

Responsible Party Unocal Foreman/Rig Manager

Recognize “Kick” Driller/Logger Logger should notify Driller of indicator. Driller to stop drilling, pick up off bottom and stop pumps. Conduct flow check. Initiate Action Unocal Foreman/Rig Manager Notify drill crew that the well is “flowing” (Drill) Simulate Shut-in Move to BOP Panel.

Driller/Crew

Time is stopped. Record this time in the Drilling Report. 64

TRIP DRILL Pit Drill/Flow Drill Action Initiate Drill Lift flow sensor or Pit float to indicate “kick” Immediately record start time.

Responsible Party Unocal Foreman/Rig Manager

Recognize “Kick” Driller/Logger Logger should notify Driller of indicator. Driller to stop drilling, pick up off bottom and stop pumps. Conduct flow check. Initiate Action Unocal Foreman/Rig Manager Notify drill crew that the well is “flowing” (Drill) Simulate Shut-In Driller/Crew Position 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.

65

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) 66


Special Problems

67

300

500

DP 300

CLOSE

CP 500

OPEN

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.

BHP 5,500

68

300

500

DP 300

CLOSE

CP 500

OPEN

Mud weight = 10ppg 10,000 X 10 X 0.052 = 5,200 psi BHP = 5,200 + 300 = 5,500 psi

TVD = 10,000 ft.

BHP 5,500

69

300

500

DP 300

CLOSE

CP 500

OPEN

From your last “choke drill” we know; KRP @40 spm = 1,000psi ICP = 1000 + 300 = 1,300 psi on DP

TVD = 10,000 ft.

BHP 5,500

70

1300

500

DP 1300

CLOSE

CP 500

OPEN

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.

BHP 5,500

71

1300

550

DP 1300

CLOSE

CP 550

OPEN

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. BHP 5,500

72

1300

650

DP 1300

CLOSE

CP 650

OPEN

BHP 5,500

73

1300

625

DP 1300

CLOSE

CP 625

OPEN

BHP 5,500

74

1300

600

DP 1300

CLOSE

CP 600

OPEN

BHP 5,500

75

1300

550

DP 1300

CLOSE

CP 550

OPEN

BHP 5,500

76

1300

700

DP 1300

CLOSE

CP 700

OPEN

BHP 5,500

77

1300

1000

DP 1300

CLOSE

CP 1000

OPEN

BHP 5,500

78

1300 1750

DP 1300

CLOSE

CP 1750

OPEN

BHP 5,500

79

1300

1000

DP 1300

CLOSE

CP 1000

OPEN

BHP 5,500

80

1300

400

DP 1300

CLOSE

CP 400

OPEN

BHP 5,500

81

1300

300

DP 1300

CLOSE

CP 350

OPEN

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

BHP 5,500

82

300

300

DP 300

CLOSE

CP 300

OPEN

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.

BHP 5,500

83

1300

300

DP 1300

CLOSE

CP 300

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.

BHP 5,500

84

1250

300

DP 1250

CLOSE

CP 300

OPEN

BHP 5,500

85

1200

300

DP 1200

CLOSE

CP 300

OPEN

BHP 5,500

86

1150

300

DP 1150

CLOSE

CP 300

OPEN

BHP 5,500

87

1100

300

DP 1100

CLOSE

CP 300

OPEN

BHP 5,500

88

1060

300

DP 1060

CLOSE

CP 300

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.

BHP 5,500

89

1060

300

DP 1060

CLOSE

CP 300

OPEN

BHP 5,500

90

1060

250

DP 1060

CLOSE

CP 250

OPEN

BHP 5,500

91

1060

200

DP 1060

CLOSE

CP 200

OPEN

BHP 5,500

92

1060

150

DP 1060

CLOSE

CP 150

OPEN

BHP 5,500

93

1060

100

DP 1060

CLOSE

CP 100

OPEN

BHP 5,500

94

1110

50

DP 1110

CLOSE

CP 50

OPEN

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

BHP 5,550

95

0

0 DP 0

CLOSE

CP 0

OPEN

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

96

DRILLERS METHOD FIRST STEP ( Remove Influx) > 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. 97

DRILLERS METHOD SECOND STEP (Change Fluid Weight) > 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.

98

BHP = HYD + GAUGE 800

1000

Choke Position Open

•

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?

Closed

9.6 ppg

10,000 ft Formation Pressure= 6000 psi

99


1100

Choke Position Pumps are constant at 40 spm.

Open

Closed

As the bubble expands, what happens to hydrostatic pressure in the annulus? 9.6 ppg

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? 10,000 ft Formation Pressure= 6000 psi

100


800

Choke Position Pump strokes are constant at 40 spm

Open

Closed

As KWF is being pumped, what is happening to the hydrostatic pressure in the DP? 9.6 ppg

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?


101

700

780

BHP = HYD + GAUGE Choke Position Pump strokes are constant at 40 spm

Open

Closed

As KWF is pumped up the annulus, what is happening to the hydrostatic in the DP? 9.6 ppg

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?


102

1600 1500

1000

Pressure Lag Time

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, choke drills, prior to drilling out the casing shoe, are recommended. 103

TD @ 23,000 ft.

CALCULATION OF KILL WEIGHT Given:

DEPTH (TVD) ORIGINAL MUD WEIGHT SHUT-IN DP PRESSURE

= 8000’ = 11 PPG = 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 ? 104

USE OF SAFETY FACTOR IN CALCULATION OF KILL WEIGHT MUD 0

GIVEN:

SICP

TD= 9000’ 9 5/8” casing shoe @ 3000’

9.625”

8 1/2” open hole

3,000 ft.

5” drill pipe 10 ppg original mud weight

Kill Mud

Original SIDPP = 500 psi Shoe tested to Leak-off @ 14 ppg EMW

Original Mud 9,000 ft. KWM used (ppg) 11.1 11.2 11.3 11.5 12.1

Assume pump is shut off when drill pipe is filled with kill mud. 8.5 “ Safety Factor (ppg) 0 .1 .2 .4 1.0

SICP (psi) 515 550 610 700 980

EMW @ Shoe (ppg) 13.3 13.6 13.9 14.5 16.3

Over/under LOT (ppg) .7 under .4 under .1 under .5 over 2.3 over

105

CASING PRESSURE CURVES WELL DEPTH = 8000’ DRILL PIPE = 5”, 19.5# KILL WT. = 10.6 ppg

HOLE SIZE = 12-1/4” MUD WT. = 9.6 ppg

CASING PRESSURE, PSI

1200

40 bbl KICK

1000

20 bbl KICK

800

10 bbl KICK

600

BEGIN 2nd. CIRCULATION

400 200 0 0

200

400

600

800

BBLS PUMPED

1000

1200 106

CASING PRESSURE CURVES WELL DEPTH = 8000’ HOLE SIZE = 12-1/4” DRILL PIPE = 5”, 19.5#

MUD WEIGHT = 9.6 ppg KILL WEIGHT = 10.6 ppg KICK VOLUME = 20 bbls

1000 CASING PRESSURE, PSI

GAS AT SURFACE 800 KILL WEIGHT MUD AT BIT

DRILLER'S METHOD

600 400 200

WAIT & WEIGHT METHOD WITH NO MIX TIME WITH 2000' MIGRATION

0 107

DEVIATED WELL PRESSURE DROP CURVES 60° HOLE WITH KICK-OFF AT 1/3 TMD

DRILL PIPE PRESSURE

1300 1200

Conventional Drill Pipe Schedule Am ou nt of Ov erb a la nc e

1100 1000 900 800 700

Correct Drill Pipe Schedule

600 500 400

0

1000

2000

STROKES

108

OTHER WELL CONTROL METHODS UNOCAL PREFERRED METHOD A. Driller’s Method

OTHER ACCEPTABLE METHODS A. Wait & Weight Method B. Top Kill C. Bottom Kill D. Lubricate & Bleed E. Volumetric (does not kill the well) F. Bullhead These Methods Are NOT Preferred

109


Special Problems

110

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

111

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

DRILLPIPE

CASING

2000

2000

1000

500

1000

3000

SPM

10 bbls.

3000

0

0

Pit Gain

800

0

3/4 7/8

OPEN

5/8 1/2 3/8 1/4 1/8

CLOSED

0 TOTAL STROKES 112

Before you get started, what will the gauges and the pit volume be when you get finished with the first step of the Driller’s Method? A. The same B. 800 psi each ± 0 pit gain.

DRILLPIPE

CASING

2000

2000

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

1000

500

10 bbls.

800

3000

0

0

SPM

Pit Gain

1000

3000

0

3/4 7/8

OPEN

5/8 1/2 3/8 1/4 1/8

CLOSED

0 TOTAL STROKES 113

Before you get started, what mud weight should be used? A. 9.6 PPG B. 10.6 PPG. C. 8.6 PPG.

DRILLPIPE

CASING

2000

2000

D. 9.0 PPG. E. 10.0 PPG.

1000

500

1000

3000

SPM

10 bbls.

3000

0

0

Pit Gain

800

0

3/4 7/8

OPEN

5/8 1/2 3/8 1/4 1/8

CLOSED

0 TOTAL STROKES 114

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 constant B. Open choke

DRILLPIPE

CASING

2000

2000

C. Close Choke D. Choke size OK E. Begin monitoring DP gauge F. Shut the well in

1000

1500

10 bbls.

800

3000

0

0

SPM

Pit Gain

1000

3000

50

3/4 7/8

OPEN

5/8 1/2 3/8 1/4 1/8

CLOSED

150 TOTAL STROKES 115

You’ve been circulating for a few minutes and everything seems to be ok. Which of the following courses of action would you take? A. Decrease stroke rate B. Open choke

E. Increase stroke rate F. Shut the well in

2000

2000

C. Close Choke D. Choke size OK

1000

1500

11 bbls.

1000

3000

800

3000

0

0

SPM

Pit Gain

CASING

DRILLPIPE

50

3/4 7/8

OPEN

5/8 1/2 3/8 1/4 1/8

CLOSED


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 B. Open choke

DRILLPIPE

CASING

2000

2000

C. Close Choke D. Choke size OK E. Increase stroke rate F. Shut the well in

1000

1800

11 bbls.

800

3000

0

0

SPM

Pit Gain

1000

3000

50

3/4 7/8

OPEN

5/8 1/2 3/8 1/4 1/8

CLOSED


Drillpipe pressure was a little to high so you corrected the problem and this is what you see. Which of the following courses of action would you take? A. Decrease stroke rate B. Open choke

DRILLPIPE

CASING

2000

2000


1000

1500

11 bbls.

750

3000

0

0

SPM

Pit Gain

1000

3000

45

3/4 7/8

OPEN

5/8 1/2 3/8 1/4 1/8

CLOSED


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? A. Decrease stroke rate B. Open choke

DRILLPIPE

CASING

2000

2000


1000

1500

12 bbls.

950

3000

0

0

SPM

Pit Gain

1000

3000

50

3/4 7/8

OPEN

5/8 1/2 3/8 1/4 1/8

CLOSED


The Casing pressure is getting close to your posted MASP. Which of the following courses of action would you take? A. Decrease stroke rate B. Open choke

DRILLPIPE

CASING

2000

2000


1000

1500

1000

3000

0

0

SPM

Pit Gain

1000

3000

50

3/4 7/8

OPEN

5/8 1/2 3/8 1/4 1/8

CLOSED

12 bbls.


It’s decision time, earn your pay. Which of the following courses of action would you take? A. Decrease stroke rate B. Open choke

DRILLPIPE

CASING

2000

2000


1000

1500

12 bbls.

1150

3000

0

0

SPM

Pit Gain

1000

3000

50

3/4 7/8

OPEN

5/8 1/2 3/8 1/4 1/8

CLOSED


It’s starting to get boring now. The driller has gone for a smoke and the AD is on the floor. Before you let him take over, you see this. Which of the following courses of action would you take? A. Decrease stroke rate B. Open choke

DRILLPIPE

CASING

2000

2000

C. Close Choke D. Choke size OK

1000

1500

1000

3000

1250

3000


0

0

SPM

Pit Gain 17 bbls.

54

3/4 7/8

OPEN

5/8 1/2 3/8 1/4 1/8

CLOSED

3500 TOTAL STROKES

122

You hear gas passing through the choke. What will happen to the casing gauge and to the pit volume as the gas is circulated out? A. Pit volume goes down and casing gauge goes up. B. Pit volume goes up and casing gauge goes up. C. Pit volume goes down and casing gauge goes down. D. Nothing E. Pit volume goes down and casing gauge goes up. F. Pit volume goes up and casing gauge goes down.

Pit Gain

DRILLPIPE

CASING

2000

2000

1000

1500

1000

3000

1250

3000

0

0

SPM

50

3/4 7/8

OPEN

5/8 1/2 3/8 1/4 1/8

CLOSED

4500

27 bbls. TOTAL STROKES

123

You hear gas passing through the choke and the Casing gauge begins too drop. Which of the following courses of action would you take? A. Decrease stroke rate B. Open choke

DRILLPIPE

CASING

C. Close Choke

2000

2000

D. Choke size OK E. Increase stroke rate F. Shut the well in

1000

1500

27 bbls.

200

3000

0

0

SPM

Pit Gain

1000

3000

50

3/4 7/8

OPEN

5/8 1/2 3/8 1/4 1/8

CLOSED


You got behind the kick and played “choke handle tennis” but finally got the gas out and the well shut-in. Which of the following courses of action would you take? A. Open choke and flow check B. Line up on KW Mud

DRILLPIPE

CASING

2000

2000

C. Continue to circulate D. Call town E. Increase Kill Weight Mud F. Shut the well in

1000

550

6 bbls.

700

3000

0

0

SPM

Pit Gain

1000

3000

0

3/4 7/8

OPEN

5/8 1/2 3/8 1/4 1/8

CLOSED


You elected to circulate longer and this is what you see. Which of the following courses of action would you take? A. Decrease stroke rate B. Open choke

DRILLPIPE

CASING

C. Close Choke

2000

2000


1000

1500

4 bbls.

550

3000

0

0

SPM

Pit Gain

1000

3000

50

3/4 7/8

OPEN

5/8 1/2 3/8 1/4 1/8

CLOSED


You have circulated longer. How do you determine it is time to shut it in? A. We have circulated more than a bottoms up. B. Pit volume gain is less.

DRILLPIPE

CASING

2000

2000

C. DP pressure is constant D. Chock is almost all the way open. E. CP is close to the initial shut in DP pressure.

Pit Gain 4 bbls.

1000

1500

1000

3000

500

3000

0

0

SPM

50

3/4 7/8

OPEN

5/8 1/2 3/8 1/4 1/8

CLOSED


You have circulated long enough and decided to shut the well in. How do shut down properly? A. Continue to hold DP constant B. Open choke

DRILLPIPE

CASING

C. Close Choke

2000

2000

D. Hold CP constant E. Increase stroke rate

1000

1500

1000

3000

SPM

4 bbls.

3000

0

0

Pit Gain

500

50

3/4 7/8

OPEN

5/8 1/2 3/8 1/4 1/8

CLOSED


You got the well shut-in. What is the calculated Kill Weight Mud that should be pumped? A. 9.6 PPG B. 10.6 PPG.

DRILLPIPE

CASING

2000

2000

C. 9.0 PPG. D. 10.0 PPG. E. 8.6 PPG. F. 11.0 PPG.

1000

500

2 bbls.

500

3000

0

0

SPM

Pit Gain

1000

3000

0

3/4 7/8

OPEN

5/8 1/2 3/8 1/4 1/8

CLOSED


You bring the pumps back up to Kill Rate Speed, pumping Kill Weight Fluid. Which of the following courses of action would you take? A. Decrease stroke rate B. Open choke

DRILLPIPE

CASING

2000

2000


1000

1500

500

3000

0

0

SPM

Pit Gain

1000

3000

50

3/4 7/8

OPEN

5/8 1/2 3/8 1/4 1/8

CLOSED

2 bbls.


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? A. 1500 psi B. 1400 psi

DRILLPIPE

CASING

2000

2000

C. 1600psi D. 1000 psi E. 1200 psi F. 1700 psi

1000

1500

500

3000

0

0

SPM

Pit Gain

1000

3000

50

3/4 7/8

OPEN

5/8 1/2 3/8 1/4 1/8

CLOSED

2 bbls.


The Drillpipe pressure began to drop so you closed the choke slightly. Which of the following courses of action should you take? A. Decrease stroke rate B. Open choke

DRILLPIPE

CASING

2000

2000


1000

1500

2 bbls.

600

3000

0

0

SPM

Pit Gain

1000

3000

50

3/4 7/8

OPEN

5/8 1/2 3/8 1/4 1/8

CLOSED


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? A. Decrease stroke rate B. Open choke C. Close Choke

DRILLPIPE

CASING

2000

2000


1000

1200

2 bbls.

500

3000

0

0

SPM

Pit Gain

1000

3000

50

3/4 7/8

OPEN

5/8 1/2 3/8 1/4 1/8

CLOSED


Everything seems to be going well, or is it? Which of the following courses of action would you take? A. Decrease stroke rate B. Open choke C. Close Choke

DRILLPIPE

CASING

2000

2000


1000

1150

2 bbls.

500

3000

0

0

SPM

Pit Gain

1000

3000

50

3/4 7/8

OPEN

5/8 1/2 3/8 1/4 1/8

CLOSED


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? A. DP=0, CP=500, and Pit Gain same. B. DP=500, CP=500, and Pit Gain = 10 bbls.

DRILLPIPE

CASING

2000

2000

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

Pit Gain 2 bbls.

1000

1050

1000

3000

500

3000

0

0

SPM

50

3/4 7/8

OPEN

5/8 1/2 3/8 1/4 1/8

CLOSED


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? A. Continue holding Casing pressure constant B. Shut-in C. Hold DP pressure constant D. Increase Mud weight

DRILLPIPE

CASING

2000

2000

1000

1050

1000

3000

500

3000


0

0

SPM

Pit Gain 2 bbls.

50

3/4 7/8

OPEN

5/8 1/2 3/8 1/4 1/8

CLOSED


You made your choice and continued to circulate. This is what you see. Which of the following courses of action would you take? A. Decrease stroke rate B. Open choke C. Close Choke

DRILLPIPE

CASING

2000

2000


1000

1050

450

3000

0

0

SPM

Pit Gain

1000

3000

50

3/4 7/8

OPEN

5/8 1/2 3/8 1/4 1/8

CLOSED

2 bbls.


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

DRILLPIPE

CASING

2000

2000

C. BHP did not change 1000

1050

1000

3000

SPM

2 bbls.

3000

0

0

Pit Gain

150

80

3/4 7/8

OPEN

5/8 1/2 3/8 1/4 1/8

CLOSED


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? A. Perform LOT at new MW B. Open annular

DRILLPIPE

CASING

2000

2000

C. Close rams D. Flow check at the choke

1000

0

1000

3000

SPM

2 bbls.

3000

0

0

Pit Gain

0

0

3/4 7/8

OPEN

5/8 1/2 3/8 1/4 1/8

CLOSED



Special Problems

140

Pressure Lag Time Measured During Choke Drill at Casing Shoe Before Drilling Ahead

141

Pressure Lag 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.

142

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.

143

12,000 ft

144

0 sec

12,000 ft

145

0 sec

12,000 ft

12 sec

146

0 sec

24 sec

12,000 ft

12 sec

147

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.

148

Reasons for Measuring PLT

Mud Type º Compressibility of Synthetic Fluid Well Geometry º Deeper Wells º Larger O.D.

>

More mud volume

149

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. 150

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.

151

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.

152

Step 1 CASING

DRILLPIPE

2000

2000

1000

300

1000

3000

300

Trap some pressure in the well.

3000

0

0

SPM

0

3/4 7/8

OPEN

5/8 1/2 3/8 1/4 1/8

CLOSED

0 TOTAL STROKES

153

Step 2 CASING

DRILLPIPE

2000

2000

1000

1000

1000

3000

300

3000

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

0

0

SPM

50 500

3/4 7/8

OPEN

5/8 1/2 3/8 1/4 1/8

CLOSED

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

TOTAL STROKES

154

Step 3 CASING

DRILLPIPE

2000

2000

1000

1000 1100

1000

3000

400

3000

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

0

0

SPM

50 550 650

5/8 1/2 3/8 3/4 1/4 7/8 1/8

OPEN

CLOSED

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.

TOTAL STROKES

155

If you did not conduct a choke drill ! CASING

DRILLPIPE

2000

2000

1000

1000

1st Step Drillers Method

1000

3000

300

3000

0

0

SPM

50

3/4 7/8

OPEN

5/8 1/2 3/8 1/4 1/8

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

CLOSED

500 TOTAL STROKES

156

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

DRILLPIPE

2000

2000

1000

900

1000

3000

300

3000

0

0

SPM

50 1000 TOTAL STROKES

3/4 7/8

OPEN

5/8 1/2 3/8 1/4 1/8

CLOSED

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. 157

CASING

DRILLPIPE

2000

2000

1000

900

1000

3000

300 2300

3000

0

0

SPM

50

3/4 7/8

OPEN

5/8 1/2 3/8 1/4 1/8

PLT Got You!

CLOSED

1150 TOTAL STROKES

158

TRY AGAIN !!

159

NOT HERE !!

160

CASING

DRILLPIPE

2000

2000

1000

900

1000

3000

400

3000

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

0

0

SPM

50

3/4 7/8

OPEN

5/8 1/2 3/8 1/4 1/8

and wait

CLOSED

and wait

1000 TOTAL STROKES

and wait….. 161

CASING

DRILLPIPE

2000

2000

1000

900

1000

3000

400

3000

0

0

SPM


3/4 7/8

OPEN

5/8 1/2 3/8 1/4 1/8

CLOSED

But 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?

162

CASING

DRILLPIPE

1000

900

Are you being patient or did you fall asleep?

2000

2000

1000

3000

400

3000

Surely you have done something by now….

0

0

SPM


3/4 7/8

OPEN

5/8 1/2 3/8 1/4 1/8

CLOSED

What kind of lag time did you have when you did the choke drill… Oh! No choke drill……………..

163

CASING

DRILLPIPE

2000

2000

Okay, paints dry. 1000

900

1000

3000

400

3000

I feel sorry for the guys still waiting….

0

0

SPM


3/4 7/8

OPEN

5/8 1/2 3/8 1/4 1/8

CLOSED

Anybody here play golf? I wonder if I’m underbalanced...

164

CASING

DRILLPIPE

2000

2000

1000

900

1000

3000

400

3000

0

0

SPM


3/4 7/8

OPEN

5/8 1/2 3/8 1/4 1/8

There is no way it should take this long… Is that a watch or a sundial on your wrist….

CLOSED

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

165

CASING

DRILLPIPE

2000

2000

1000

900

1000

3000

400

3000

0

0

SPM

50

3/4 7/8

OPEN

5/8 1/2 3/8 1/4 1/8

CLOSED

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….

1125 TOTAL STROKES

Will it be like this on the simulator …. 166

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

DRILLPIPE

2000

2000

1000

1000

1000

3000

400 300

3000

0

0

SPM

50

3/4 7/8

OPEN

5/8 1/2 3/8 1/4 1/8

CLOSED

1150 TOTAL STROKES

167

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.

168

Questions or Comments?

169


Special Problems

170

LEAK-OFF TESTING, WELL DESIGN and WELL CONTROL

171

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.

172

All three use the following: •The U-Tube •Pressure •Boyles Law (P1V1 = P2V2) •Pore Pressure (formation pressure) •Fracture Gradients (how strong is the formation)

173

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.

174

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. 175

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).

176

Total Pressure at the shoe = Hydrostatic + Surface Press. Fracture Pressure is the Total Pressure that causes the rock to break and split apart.

FRAC PRESS

Once the pressure is removed the overburden will force the rock to close and it regains it’s integrity until the Fracture Press is re-applied. 177

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.

178

LOT VS. FIT LOT • Exploration Well • Development well on a new platform. • Development well in an old field that has

FIT • Development well with several other wells in the field. • Cannot perform a LOT

not been drilled in lately. 179

LOT GUIDELINES The adoption of a standard leak-off test procedure that specifies the following is recommended. 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 180 +/- 2% or better be used).

LEAK OFF TEST 4000 Drill Pipe Casing

3500

P 3000 R E S 2500 S U 2000 R E

2090 psi in 10 sec shut in

1500 P S I 1000 500 1

2

3

4

5

6

0 0

2

4

6

7 8 9 BBL PUMPED

8

10

10

TIME (MIN)

Pump Stopped

12

14

16

18

181

LOT Data

DATA INPUT: Well Name (max 8 characters) Date: WELL Data: Rotary Table: Water Depth: Casing Size: Casing Shoe Depth: Casing Shoe Vertical Depth: LOT Data: Mud Weight: 10 sec. Casing Pressure: Pump Rate:

Trat A-06 19 Nov. 1998 106 ft above MSL 240 ft 7 inch 10441 ft MD 8232 ft TVD 11.3 ppg 2090 psi 1.0 BPM

182

VOLUME BBLS 0.0 1.0 2.0 3.0 4.0 5.0 6.0 7.0 8.0 9.0

PRESSURES (PSI) Drillpipe Casing 0.0 0.0 262.0 178.0 669.0 600.0 1011.0 942.0 1418.0 1341.0 1901.0 1804.0 2352.0 2239.0 2820.0 2719.0 3335.0 3198.0 2719.0 2513.0

TIME Minutes 0.0 1.0 2.0 3.0 4.0 5.0 6.0 7.0 8.0 9.0

10.0 11.0

2268.0 2276.0

2159.0 2159.0

10.0 11.0

12.0 13.0

2252.0 2252.0

2127.0 2127.0

12.0 13.0

14.0 After Stop Pumping 14.0

2207.0

2094.0

14.0

2050.0

2090.0

14.2 (10 sec shut-in)

14.0 14.0

1945.0 1929.0

1929.0 1901.0

15.0 16.0

14.0

1929.0

1889.0

17.0

183

KICK TOLERANCE AND BOYLES LAW

184

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) 185

• 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 • Assumptions 1) Kick is 100% gas. 2) Fluid is WBM - No gas goes into solution. 186

649

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

Gauge Pressure = 18,829 - 4,527 - 19 - 13,634 = 649 psi Pressure at the shoe = 649 + 13,364 = 14,013 psi I have not exceeded the Fracture Pressure so the well design would be valid.

14,013

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

192 ft of gas = 32.4 192 xbbl 0.1when psi/ft = 19 brought to the shoe. psi hydrostatic 6,308 ft of 13.8 ppg = 4,527 psi

25 bbl kick at BHP of 18,829 psi

187

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.

188

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

189

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.

190

Equation Triangle P1 x V1 = P2 X V2 P1 is the pressure that the gas is under. P1 = BHP V1 is the size of kick V1 = Barrels P2 is the pressure of the gas at it’s new position in the well.

P1 x V1

P2 = Hydrostatic + Gauge Pressure

P2

X

V2

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

191

Equation Triangle P1 x V1 = P2 X V2 P1 = 18,829 psi V1 = 25 bbls P2 = 14,524 psi V2 = ?

18,829 P1 x VX1 25

18,829 X 25 = 32.4 bbls 14,524 On your calculator you would key in: • 18,829 x 25 = (470,725) ÷ 14,524 =

P2 14,524

X

V?2 192

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’.

193

• 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’ 194

DPP

}

Water

.

.

7129’

Sea bed

19,000’/ 11,871’ BML

25,500’/ 18371’ BML

HYDROSTATIC PRESSURE (HP)

CP

}B

}c

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’ A

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

195

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.

196

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 197

RKB MSL

92’ Air 7037’ Water

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

Mudline

B) What is the rock fracture gradient (FG)? 11,871’ Rock

Fracture Press. = HYD Press water + HYD Press rock 14,524 = (7037’ X 0.447) + (11871 X FG) 14,524 = 3146 + (11,871 X FG)

19,000’/ 11,871’ BML

FG = (14,524 - 3146) ÷ 11871 = 0.95 psi/ft 198

• 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.

199

RKB 92’ Air MSL 7037’ Water Mudline

11,871’

Rock

19,000’

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

200

RKB

RKB 92’ Air

MSL 7037’ Water Mudline

82’ Air MSL 2600’ Water Mudline

11,871’

Rock

16,316’

Rock

19,000’

Shoe

19,000’

Shoe



LOT Press. = 14,524 psi


19,000’ = .764 psi/ft

19,000’ = .764 psi/ft

= .764psi/ft = 14.7

= .764psi/ft = 14.7

00.052

00.052

Rock Frac Grad. = 14,524 - 7037 X .447 = 11,379 psi 11,379 psi ÷ 11,871’ = 0.95 psi/ft

Rock Frac Grad. = 14,524 - 2600 X .447 = 13, 362 psi 13,362 psi ÷ 16,316’ = 0.82 psi/ft

201

RKB

RKB

RKB




11,871’

Rock

16,316’

Rock

16,316’

Rock

19,000’

Shoe

19,000’

Shoe

19,000’

Shoe







19,000’ = .764 psi/ft

19,000’

19,000’

= .764 psi/ft

= .879 psi/ft

= .764psi/ft = 14.7

= .764psi/ft = 14.7

= .879psi/ft = 16.9

00.052

00.052

00.052

Rock Frac Grad. =

Rock Frac Grad. =

14,524 - 2600 X .447 =

16,697 - 2600 X .447 =

13, 362 psi

15,534 psi

13,362 psi ÷ 16,316’ =

15,534 psi ÷ 16,316’ =

0.82 psi/ft

0.95 psi/ft


202

RKB

RKB

RKB




RKB 84’ Air MSL 2600’ Water Mudline 11,871’

11,871’

Rock

16,316’

Rock

16,316’

Rock 14,555’

19,000’

Shoe

19,000’

Shoe

Rock

19,000’

Shoe

Shoe Frac. Press. = 12,440 psi



Frac. Press. = 16,697 psi LOT Press. = 12,420 psi

LOT Press. = 14,524 psi 19,000’ = .764 psi/ft



19,000’

19,000’

= .764 psi/ft

= .879 psi/ft

= .764psi/ft = 14.7

= .764psi/ft = 14.7

= .879psi/ft = 16.9

00.052

00.052

00.052

Rock Frac Grad. =

Rock Frac Grad. =

14,524 - 2600 X .447 =

16,697 - 2600 X .447 =

13, 362 psi

15,534 psi

13,362 psi ÷ 16,316’ =

15,534 psi ÷ 16,316’ =

0.82 psi/ft

0.95 psi/ft


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

203

SHALLOW LEAK-OFF TEST DRIVES THE WELL DESIGN

204

LEAK-OFF TESTS BELOW IS A VERY SMALL SAMPLING OF OUR MANY THOUSANDS OFL.O.T. STATISTICS WELL NAME

FRAC LOCATION DEPTH

BS 52#1 GOM A-19 Cal 16-2CT Midland A-17 Cal Sibual 2-2 Indo YC-2 Indo 220 Midland Yakin YC-5HZ Indo 201 Midland

186 393 396 397 403 414 420 421 424

WELL GRAD

1.08 .93 1.02 .92 1.46 1.02 1.18 1.05 1.00

WELL NAME

LOCATION

Attaka#32 Indo Sakon #1 Thai VE 66 #3 GOM BA #28 Alaska EHI 302 A-13 GOM A-20 Cal VE 328 #2 La A-19 Cal Kham Palai #1Thai BA #28 Alaska B-KL-1X Vietnam #1-9 Michigan

FRAC DEPTH

WELL GRAD

448 495 562 582 679 681 681 755 774 802 814 869

1.00 .92 .83 .94 .89 1.18 .81 .93 1.77 .94 .94 1.71

205

LOCATION OF SECOND CASING SHOE (THE KEY TO SHALLOW WELL CONTROL) FIRST CEMENTED SHOE INCREASING EXPOSURE

SECOND CEMENTED SHOE

•

MORE TIME

•

MORE POSSIBILITY OF ENCOUNTERING GAS

DECREASING RESISTANCE TO FRACTURE (PSI)

206

RECOMMENDED DESIGN / OPERATIONS APPROACH 1. Design well to shut-in. 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. 207


Special Problems

208

Shallow Hazards 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.

209

Shallow Hazard Examples 

Pipelines and man made structures



Unstable Seafloor: faults, slumps, and channels



Gas vents and mud volcanoes



Hydrates (“Primary and Secondary”) Chemosynthetic Communities



Subsurface water, gas and sediment flows (SWF)

210

Gas Hydrates

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

211

Hydrate Formation Form at high pressures and low temperatures 40 degrees F and 780 psia 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* 212 * Sloan 1998

Hydrate Hazards 

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)

213

Kutai Basin, Indonesia Hydrate X-Section

Hydrates

214

Subsurface Hydrates

GR

RES

WD : 5312’ 5635’

Hydrates Interval

-5987’

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

215

Hydrate Characteristics Kutai Basin, Indonesia 

     

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) 216

Hydrate Drilling SOP Indonesia* 

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

217

Shallow Water Flows (SWF)

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.

218

Overpressure Mechanisms

219 From paper by Pelletier 1999 SWF Forum

Overpressure Mechanisms • Remember the sponges and • Charged formation

220

Problems Associated with SWFs 

Uncontrolled Water Flows



Sediment washout (cement integrity)



Sediment Compaction



Casing Collapse and Buckling



Formation of seafloor craters, mounds and cracks

221

ERWE-19 WELL-SEC

Water Depth = 198’ SSD

Prog.@-732’ SSD of top gas sand

Final Depth-923’ SSD

Two-way time ms.

Depth (Ft. SS.)

Prog.@-902’ SSD of top gas sand

222

223

Unocal Deepwater Shallow Hazard Assessment Integrated Team Work 

Geology



Geophysics



Drilling



Petrophysics

224

Geomechanics 

Overburden Assessment



Fracture Gradient Prediction



Pore Pressure Prediction



Offset and Regional Mud and LOT data



Real Time analysis with PWD and ROV

225

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

226

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. 227

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 228

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

229

First Hole Section- Riser or Riserless?

230


Special Problems

231

SHALLOW GAS KICKS 1980-1989 CERVEZA - 1983 2500’

4000’

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

GRAYLING - 1985 420’

3565’

$35 Million

456’

1225’

5 Fatalities Multiple Injuries

• 1 - 4” line • Diverter Failed • No Fire • Breached $40 Million

ATTAKA J1 - 1981 • Diverter Failed • Fire

• Diverted

STEELHEAD - 1987 766’

2265’

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

$150 Million (Operated by Marathon)232

SHALLOW GAS KICKS 1990 - 2000 Attaka 38 - 1998

Attaka 38a - 1998

• Gas in water

500’

• Moved rig off location • Flow stopped on its own

• Gas in water

460’

No Injuries Minimal Cost

No Injuries Minimal Cost

B-TXT-2X - 2000

Molavia Bazar - 1997

• Gas in water

915’

• Evacuated Rig • Flow stopped on its own No Injuries Minimal Cost

• Evacuated Rig • Flow stopped on its own

509’

2755’

• Diverter system failed • Fire • Breached •$10+ Million (Operated by Oxy) 233

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 ! 234

Well Control Equipment 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.

Checklist: Well Control Equipment Check temperature rating for elastomers, particularly in variable bore rams. If shear rams are installed, ensure that the shear rams can, in fact, shear all grades of drill pipe in use.

235

BOP CONSIDERATIONS ANNULAR

PIPE RAMS BLIND RAMS

TO KILL LINE

TO CHOKE LINE PIPE RAMS

WELLHEAD

236

Well Control Equipment

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

237

USEABLE FLUID To 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 gal N2

238

Equation Triangle P1 x V1 = P2 X V2 P1 = 1000 psi V1 = 10 gal P2 = 1200 psi V2 = ?

1000 P1 x X V110

1000 X 10 = 8.3 gal of Nitrogen 1200 10 - 8.3 = 1.7 gal of fluid

P2 1200

X

V?2

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

239

USEABLE FLUID It takes 1.7 gallons of fluid to compress the Nitrogen to the Minimum System Pressure of 1200 psi. 1000

1200

10 gal N2

8.3 gal N2

1.7 gal Fluid 240

Equation Triangle P1 x V1 = P2 X V2 P1 = 1000 psi V1 = 10 gal P2 = 3000 psi V2 = ?

1000 P1 x X V110

1000 X 10 = 3.3 gal of Nitrogen 3000 10 - 3.3 = 6.7 gal of fluid

P2 3000

X

V?2

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

241

USEABLE FLUID To 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.

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)

1200

3000

8.3 gal N2

3.3 gal N2

•

Useable Fluid

1.7 gal Fluid

6.7 gal Fluid 242

Accumulator Volume

18 gal. to close

3000 psi

7 gal. To close

Atmospheric Pressure

6 gal. To close

1 gal. To open

7 gal. To close

Total gallons to close = 39 gallons 39 gal. X 1.5 safety factor = 59 gal. Of useable fluid required 59 gal. X 2 = 118 gal. Of total stored fluid 118 ÷ 10 = 11.8 or 12 bottles 243


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.

244


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.

245

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. 246

Well Control Equipment 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.

247

GAS BUSTER GAS

Vent Line

NO VALVES!

• Diameter & length of vent line controls amount of pressure in separator Inspection Cover

Pressure Gauge

Baffle Plates

Impingement Plate

From Choke

Siphon Breaker

d To Mud Degasser

NO VALVES! D Drain Line With Valve

• Height, Diameter & Internal design controls separation efficiency

• 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 248

Well Control Equipment 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.

249

BOP TESTING RECOMMENDED FIELD TESTS: Ram Preventers Annular Preventers

Low 200-300 psi “

High WP or CSG. Burst 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? 250

Intro Pressure Basics (The U-Tube) Kicks & Shut-in Drillers Method Gauge Questions Pressure Lag Time LOT & Well Design Shallow Hazards Equipment SBM Special Problems

251

SBM OBM Gas Kicks: migration, solubility. Ballooning;

252

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.

253

Facts about Synthetic Base and Oil Base Muds Gas migrates in SBM / OBM until it goes into solution. Gas enters the wellbore at full volume. Gas in solution may have one half the volume as does gaseous gas. Gas come out of solution at rates depending on temperature, pressure and concentration. 254

Solubility vol/vol 6000 5000 4000 Pressure West North

3000 2000 1000 0 -1000

0

200

400

600

255

Boyle’s Law • P1 x V1 = Constant • P1 x V1 = Constant = P2 x V2 Known information

Any point in the well

256

Boyle’s Law (continued) 11.0ppg MW

P2 = ?2,860 psi

5,000’

V2 = P1 x V1 ÷ P2 = ? 20 bbl

10 bbl

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

257

Temperature (°F) 78

200

350

Pressure (psig) 0 3,000 6,000 9,000 12,000 15,000 0 3,000 6,000 9,000 12,000 15,000 3,000 6,000 9,000 12,000 15,000

Pressure / Temperature Effect on Density

Measured Density ( lbm/gal) 17.000 17.145 17.275 17.389 17.492 17.589 16.392 16.592 16.760 16.905 17.033 17.149 15.890 16.122 16.310 16.469 16.608

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

258

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 pit gain 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. 259

Volume At Surface • 12.4 ppg SBM • The well unloaded 30 bbls at Bottoms Up.

• 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?

6” Open Hole to TD@12,000

260

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. 261

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.

262

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.

263

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. 264

Ballooning / Micro Fracturing

265

Connection Flow Monitor - Breathing 150

130 Feb. 14, 142 bbl. Breathing 110

Change Pit Vol., bble

Feb. 15, 112 bbl. Breathing 90 Feb. 14, 80 bbl. No breathing

70

50

30

10

1

2

3

4

5

6

7

8

9

-10 Time, min.

10

11

12

13

14

15

16

17

266

Connection Flow Monitor - Flowing 150

130 Jan.. 12, well flowing, 140 + bbls 110

Change Pit Vol., bble

Point of infelction 90 Jan. 10, start of interval, 100 bbls. No breathing

70

50

30

10

1

2

3

4

5

6

7

8

9

-10

10

11

12

13

14

15

16

17

267 Time, min.

268

Intro Pressure Basics (The U-Tube) Kicks & Shut-in Drillers Method Gauge Questions Pressure Lag Time LOT & Well Design Shallow Hazards Equipment SBM Special Problems

269

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: • Fast Transition Time- Right set cement • 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 270 Remain Alert!

ABANDONING A “DEAD” WELL

Air

Air

Heavy Fluid Oil

Water Producing Zone

271

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

272

BROKEN U-TUBES

This requires a high rate of losses. Slight losses can be dealt with during the regular Drillers Method.

273

RECOGNIZING BROKEN U-TUBES • A sudden break back in surface pressures • Fluctuations in casing pressure • Fluctuations in drillpipe pressure • Numerous choke changes • Loss of communication between drillpipe & annulus • Drillpipe pressure decreasing or on vacuum • Sudden vibration in drillpipe, BOP, and/or tree 274

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.

275

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. 276

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.

277

COMMON CONTROL METHODS To improve your chance of success with the previous methods, formulate a strategy that includes; • Knowledge of the location, pressure, and flow characteristics of the producing and loss zones and the flow path • 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 278 predicted.

MECHANICAL COMPLICATIONS = HAPPENS FIRST

COMPLICATION

= HAPPENS AFTER TIME LAG

DP GAUGE

CP GAUGE NO CHANGE

PLUGGED JET PLUGGED CHOKE WASHED CHOKE LOSING CIRCULATION HOLE IN WORKSTRING HOLE PACKED OFF

WILL FOLLOW CP WITH SMALLER SWINGS

ERRATIC FLUCTUATING NO CHANGE

279

INTACT U-TUBE DRILLERS METHOD CLEAR INFLUX

DP GAUGE KEEP CONSTANT

CP GAUGE SLOWLY INCREASING

KWF TO BIT

DECREASING

KEEP CONSTANT

KWF TO SURFACE

KEEP CONSTANT

SLOWLY DECREASING

PIT CHOKE GAIN DIRECTION INCREASING MOSTLY THEN BACK OPENING TO ORIGINAL CONSTANT NO CHANGE CONSTANT

MOSTLY OPENING

280

WELL CONTROL LOG TIME

DP PSI

CASING PSI

CHOKE SIZE

STROKES

PIT GAIN

COMMENTS

281

ORGANIZING & DIRECTING IN WELL CONTROL Value of Rig Crew Drills - TEAMWORK • Keeps possibility of kick control in minds of crew and supervisors (like school). • Gets everyone familiar with the equipment on the rig and get more comfortable with the procedures. • 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. 282

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. 283

Formulas 1 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

284

Formulas 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 ChangeChange New Pump Pressurepsi = Original Pressurepsi x (New Mud Weightppg ÷ Old Mud Weightppg)

285

Contact Information Rick Dolan: [email protected]

George Grundt: [email protected]

Benny Mason: [email protected]

286

Drilling Basic 2001 Manual

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