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Drilling Basic 2001 Manual
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1© Union Oil of California, dba Unocal 2001All rights reserved
DR
ILL
ING B
AS
IC
TRAINING MANUAL
2
Pressure Basics (The U-Tube)
Kicks & Shut-in
Drillers Method
Gauge Questions
Pressure Lag Time
LOT & Well Design
Shallow 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 - richard.dolan@unocal.com
Benny Mason - (281) 287-7545 - bmason@unocal.com
George Grundt - (281) 287-7254 - ggrundt@unocal.com
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
Pressure Basics (The U-Tube)
Kicks & Shut-in
Drillers Method
Gauge Questions
Pressure Lag Time
LOT & Well Design
Shallow Hazards
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’
Pressure
In 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 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.
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
If you want to solve for MW or TVD, fill in the known information and the equation is written for you.
MWppg = 500 572
23
Equation Triangle
Pressurepsi
MWppg X 0.052 X TVDft
If you want to solve for MW or TVD, fill in the known information and the equation is written for you.
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
33
6000 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
? bbls GasTop of gasat 5000 ft.
? bbls GasTop of gasat 1000 ft.
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
Pressure Basics (The U-Tube)
Kicks & Shut-in
Drillers Method
Gauge Questions
Pressure Lag Time
LOT & Well Design
Shallow Hazards
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
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
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 pulling
balled 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.
Stop pumps & check for flow
Stop pumps & check for flow
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”)
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.
62
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.
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
Pressure Basics (The U-Tube)
Kicks & Shut-in
Drillers Method
Gauge Questions
Pressure Lag Time
LOT & Well Design
Shallow Hazards
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 = 1,000psi
ICP = 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
650
DP1300
CP650
BHP5,500
1300
74
CLOSE OPEN
625
DP1300
CP625
BHP5,500
1300
75
CLOSE OPEN
600
DP1300
CP600
BHP5,500
1300
76
CLOSE OPEN
5501300
DP1300
CP550
BHP5,500
77
CLOSE OPEN
700
DP1300
CP700
BHP5,500
1300
78
CLOSE OPEN
1000
DP1300
CP1000
BHP5,500
1300
79
CLOSE OPEN
1750
DP1300
CP1750
BHP5,500
1300
80
CLOSE OPEN
1000
DP1300
CP1000
BHP5,500
1300
81
CLOSE OPEN
400
DP1300
CP400
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.
300
DP1300
CP300
BHP5,500
1300
85
CLOSE OPEN
300
DP1250
CP300
BHP5,500
1250
86
CLOSE OPEN
300
DP1200
CP300
BHP5,500
1200
87
CLOSE OPEN
300
DP1150
CP300
BHP5,500
1150
88
CLOSE OPEN
300
DP1100
CP300
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.
300
DP1060
CP300
BHP5,500
1060
90
CLOSE OPEN
300
DP1060
CP300
BHP5,500
1060
91
CLOSE OPEN
250
DP1060
CP250
BHP5,500
1060
92
CLOSE OPEN
200
DP1060
CP200
BHP5,500
1060
93
CLOSE OPEN
150
DP1060
CP150
BHP5,500
1060
94
CLOSE OPEN
100
DP1060
CP100
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.
BHP5,500
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
Formation Pressure= 6000 psi
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
Formation Pressure= 6000 psi
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
Formation Pressure= 6000 psi
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 WEIGHT
Given: 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
RE
SS
UR
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
RE
SS
UR
E,
PS
I
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
PIP
E P
RE
SS
UR
E 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 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
110
Pressure Basics (The U-Tube)
Kicks & Shut-in
Drillers Method
Gauge Questions
Pressure Lag Time
LOT & Well Design
Shallow Hazards
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 same
B. 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 PPG
B. 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 constant
B. 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 rate
B. 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
E. Increase stroke rate
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.
A. Decrease stroke rate
B. Open choke
C. Close Choke
D. Choke size OK
E. Increase stroke rate
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.
A. Decrease stroke rate
B. Open choke
C. Close Choke
D. Choke size OK
E. Increase stroke rate
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.
A. Decrease stroke rate
B. Open choke
C. Close Choke
D. Choke size OK
E. Increase stroke rate
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.
A. Decrease stroke rate
B. Open choke
C. Close Choke
D. Choke size OK
E. Increase stroke rate
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
E. Increase stroke rate
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.
A. Decrease stroke rate
B. Open choke
C. Close Choke
D. Choke size OK
E. Increase stroke rate
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 check
B. 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.
A. Decrease stroke rate
B. Open choke
C. Close Choke
D. Choke size OK
E. Increase stroke rate
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 constant
B. Open choke
C. Close Choke
E. Increase stroke rate
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 PPG
B. 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
A. Decrease stroke rate
B. Open choke
C. Close Choke
D. Choke size OK
E. Increase stroke rate
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 psi
B. 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
A. Decrease stroke rate
B. Open choke
C. Close Choke
D. Choke size OK
E. Increase stroke rate
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
A. Decrease stroke rate
B. Open choke
C. Close Choke
D. Choke size OK
E. Increase stroke rate
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
A. Decrease stroke rate
B. Open choke
C. Close Choke
D. Choke size OK
E. Increase stroke rate
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 constant
B. Shut-in
C. Hold DP pressure constant
D. Increase Mud weight
E. Increase stroke rate
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
A. Decrease stroke rate
B. Open choke
C. Close Choke
D. Choke size OK
E. Increase stroke rate
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 decreased
B. 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 MW
B. 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
Pressure Basics (The U-Tube)
Kicks & Shut-in
Drillers Method
Gauge Questions
Pressure Lag Time
LOT & Well Design
Shallow Hazards
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 3
Make 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
Pressure Basics (The U-Tube)
Kicks & Shut-in
Drillers Method
Gauge Questions
Pressure Lag Time
LOT & Well Design
Shallow Hazards
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 18
TIME (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) TIME
BBLS Drillpipe Casing Minutes
0.0 0.0 0.0 0.0
1.0 262.0 178.0 1.0
2.0 669.0 600.0 2.0
3.0 1011.0 942.0 3.0
4.0 1418.0 1341.0 4.0
5.0 1901.0 1804.0 5.0
6.0 2352.0 2239.0 6.0
7.0 2820.0 2719.0 7.0
8.0 3335.0 3198.0 8.0
9.0 2719.0 2513.0 9.0
10.0 2268.0 2159.0 10.0
11.0 2276.0 2159.0 11.0
12.0 2252.0 2127.0 12.0
13.0 2252.0 2127.0 13.0
14.0 2207.0 2094.0 14.0
After Stop Pumping
14.0 2050.0 2090.0 14.2 (10 sec shut-in)
14.0 1945.0 1929.0 15.0
14.0 1929.0 1901.0 16.0
14.0 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
• AssumptionsAssumptions
1) 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
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
Shoe
RKB
MSL
Mudline
82’ Air
2600’ Water
19,000’
16,316’ Rock
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 - 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
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
Shoe
RKB
MSL
Mudline
82’ Air
2600’ Water
19,000’
16,316’ Rock
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 - 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
Frac. Press. = 16,697 psi
LOT Press. = 16,697 psi
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
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
Shoe
RKB
MSL
Mudline
82’ Air
2600’ Water
19,000’
16,316’ Rock
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 - 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
Frac. Press. = 16,697 psi
LOT Press. = 16,697 psi
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
Frac. Press. = 12,440 psi
LOT Press. = 12,420 psi
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
Pressure Basics (The U-Tube)
Kicks & Shut-in
Drillers Method
Gauge Questions
Pressure Lag Time
LOT & Well Design
Shallow Hazards
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)
219
From 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 t
ime
ms.
Dep
th (
Ft.
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
Pressure Basics (The U-Tube)
Kicks & Shut-in
Drillers Method
Gauge Questions
Pressure Lag Time
LOT & Well Design
Shallow Hazards
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
No InjuriesMinimal Cost
B-TXT-2X - 2000• Gas in water• Evacuated Rig• Flow stopped on its own
No InjuriesMinimal Cost
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 !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
Well Control Equipment
Accumulators Should have sufficient ‑volume to close and hold closed all preventers and maintain accumulator pressure above minimum system pressure.
238
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 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
Well Control Equipment
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
Well Control Equipment
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
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.
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 Degasser
NO VALVES!
Inspection Cover
249
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.
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
Pressure Basics (The U-Tube)
Kicks & Shut-in
Drillers Method
Gauge Questions
Pressure Lag Time
LOT & Well Design
Shallow Hazards
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
Pressure
West
North
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.
Ch
ang
e P
it V
ol.,
bb
le
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.
Ch
ang
e P
it V
ol.,
bb
le
Jan. 10, start of interval, 100 bbls.No breathing
Point of infelction
Jan.. 12, well flowing, 140 + bbls
268
269
Pressure Basics (The U-Tube)
Kicks & Shut-in
Drillers Method
Gauge Questions
Pressure Lag Time
LOT & Well Design
Shallow Hazards
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
WELL CONTROL LOGTIME DP
PSICASING
PSICHOKE
SIZESTROKES PIT
GAINCOMMENTS
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:richard.dolan@unocal.com
George Grundt:grundt@unocal.com
Benny Mason:bmason@unocal.com
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