Wellbore Problems and Mitigations PDF
Wellbore Problems and Mitigations PDF
Wellbore Problems and Mitigations PDF
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TABLE OF CONTENTS
WELL PLAN
BASIC GEOLOGY .................................................................................................. 2
CASING PROGRAM .............................................................................................. 9
DRILLING FLUIDS ................................................................................................ 15
HYDRAULICS PLANNING .................................................................................... 20
STUCK PIPE
HOLE PACK-OFF/BRIDGE .................................................................................... 22
DIFFERENTIAL STICKING .................................................................................... 44
WELLBORE GEOMETRY ..................................................................................... 47
STUCK PIPE FREEING ......................................................................................... 53
LOST CIRCULATION
LOST CIRCULATION MECHANISMS .................................................................... 56
SEEPAGE LOSS SOLUTIONS .............................................................................. 60
PARTIAL LOSS SOLUTIONS ................................................................................ 61
TOTAL LOSS SOLUTIONS ................................................................................... 61
PILL SPOTTING GUIDELINES ............................................................................. 63
RIG REPAIR
IMPACT OF UNSCHEDULED RIG REPAIR .......................................................... 66
INTERGRATING PMP WITH WELL PLAN ............................................................ 68
DRILLING SYSTEM EMERGENCY PROCEDURE................................................ 69
DRILLING JARS
BASIC JAR OPERATIONS................................................................................... 81
PUMP OPEN FORCE ......................................................................................... 82
COCKING /TRIPPING THE JAR ......................................................................... 83
DRILLING ACCELERATOR ............................................................................... 86
JAR RULES / PLACEMENT GUIDELINES ........................................................ 87
WELL CONTROL
PRIMARY WELL CONTROL ................................................................................ 91
SWAB / SURGE PRESSURE .............................................................................. 92
SECONDARY WELL CONTROL ........................................................................ 95
KICK DETECTION / SHUT-IN TEAM ................................................................... 97
TERTIARY WELL CONTROL ............................................................................. 111
KICK OBM DETECTION / GAS BEHAVIOR ...................................................... 115
WELL CONTROL KILL SHEET .......................................................................... 117
CASING /CEMENTING
CEMENTING CONSIDERATIONS ..................................................................... 119
STANDARD EQUIPMENT .................................................................................. 121
EQUIPMENT /WELLBORE PREPARATIONS ..................................................... 122
CASING PRE JOB CHECKLIST .......................................................................... 125
RUNNING CASING GUIDELINES ....................................................................... 126
CEMENTING PRE JOB CHECKLIST .................................................................. 127
TROUBLE SHOOTING CEMENTING PROBLEMS ............................................ 130
HORIZONTAL DRILLING
WHY DRILL HORIZONTAL WELLS .................................................................... 131
HORIZONTAL WELL PROFILES ......................................................................... 132
HORIZONTAL DRILLING BHA ........................................................................... 133
HORIZONTAL WELL PLANNING ........................................................................ 134
HORIZONTAL WELL CONTROL KILL SHEET .................................................... 136
INVESTIGATION PACKAGE
DRILLER HANDOVER NOTES ........................................................................... 138
SHAKER HANDOVER NOTES ........................................................................... 139
TIGHT HOLE / STUCK PIPE REPORT FORM .................................................... 140
LOST CIRCULATION REPORT FORM ............................................................... 141
EQUIPMENT SELECTION / INSPECTION FORM ............................................ 142
DOWN HOLE TOOL FAILURE REPORT FORM ................................................. 143
DRILL STRING FAILURE REPORT FORM ......................................................... 144
WELL CONTROL EVENT REPORT FORM ......................................................... 145
TEAM BUILDING PRINCIPLES
TEAMS
WHAT ARE TEAMS
Two or more people working together
Functional experience
Inter-personal skills
PROBLEM SOLVING
HOW DO TEAMS SOLVE PROBLEMS
Define the problem
WORKING STYLES
TEAM DECISION MAKING STYLES
COMMAND Decision is made by leader
Page 1
BASIC GEOLOGY WELL PLAN
FORMATION A laterally continuous sequence of sediments that is recognizably distinct and mappable
Rock fragments (sand, silt, clay) and dissolved chemical compounds (silicates, calcite, iron,
TRANSPORTATION etc.) are transported to the basin by gravity, flowing water and wind
The fragments are swept into the basin where they settle to the floor of the basin and form
SEDIMENTATION water saturated beds of sand and clay
EVAPORATION
SEDIMENTARY
ROCKS
IGNEOUS
ROCK
BASIN
The weight of each successive sediment layer (overburden) compacts the sediments below. Compaction
COMPACTION squeezes the water out of the sediments and back to the sea
CEMENTATION As the water is squeezed out, the dissolved chemical compounds left behind cements the
fragments together to form sedimentary rock
Page 2
WELL PLAN BASIC GEOLOGY
CLAYSTONE CLst Less than Rocks formed from an accumulation of clay minerals and silt size particles
& SHALE Sh 4 microns
MARL Mrl Less than Rocks formed from an accumulation of clay minerals and calcite (calcium
4 microns carbonate)
4 to 60
SILTSTONE SLst
microns Rocks formed from an accumulation of mineral grains (quartz).
Greater than Rocks formed from an accumulation of primarily granule, pebble and boulder
CONGLOMERATE Cgl size particles
2mm
LIMESTONE Ls Rocks formed from large deposits of primarily calcite (calcium carbonate) and
dolomite (calcium magnesium)
DOLOMITE & Dol Chemical
CHALK Chk Rocks
Compressive strengths: Limestone, +/- 20,000 psi; Dolomite, +/- 24,000 psi;
Chert, +/- 83,000 psi; Chalk, +/- 6000 psi;
CHERT Cht
Gypsum & Gyp Rocks composed of minerals that precipitated from solution during the
Anhydrite Anhy evaporation of water
Evaporates
Compressive strength: Anhydrite +/- 6000 psi
SALT Sa
BASEMENT Bm
Igneous Rock formed from the cooling of molten magma
rock
VOLCANICS Volc
LT
FAULT Flt A geologic A fracture in the rock caused by natural forces resulting in failure and
U
feature
Native
GAS G formation
Gaseous hydrocarbon (2.3 ppg average)
fluids
Page 3
BASIC GEOLOGY WELL PLAN
FORMATION POROSITY
TYPICAL POROSITY REDUCTION BY
SEDIMENT COMPACTION AND CEMENTATION
NO FILTER
CAKE 0
DEPTH (1000')
SHALE SAND
10
15
FLUID TRAPPED 20
IN PORE SPACES NOTE: Deviations from the
average porosity can occur
at any depth
SHALE WELLBORE
25
0 10 20 30 40 50
POROSITY %
5 SANDS
DEPTH (1000')
10 SHALES
15
CONNECTED POROSITY 20
PROVIDES PERMEABILITY NOTE: Deviations from the
average permeability is
possible at any depth
SANDSTONE WELLBORE 25
0 1 2 3 4 5
PERMEABILITY (Darcies)
Page 4
WELL PLAN BASIC GEOLOGY
OVERBURDEN The stress produced by the combined weight of the rocks and formation fluids overlaying
STRESS a depth of interest
TYPICAL OVERBURDEN
STRESS VERSUS DEPTH
0
DEPTH (1000')
6
9
VERTICAL STRESS
OF OVERBURDEN
12
HORIZONTAL STRESS
12.5 ppg OF OVERBURDEN 12.5 ppg 15
14.0 18
ppg 10 12 14 16 18 20
OVERBURDEN STRESS ppg
Generated by the force of gravity, the overburden exerts a vertical stress to the formations. A resulting value of horizontal stress
is developed depending on rock stiffness (as rock stiffness increases, horizontal stress decreases)
TECTONIC The stress produced by lateral (side to side) forces in the formation
STRESS Tectonic stresses are usually very high in mountainous regions
SIDE
VIEW
ST
IC RE
ON SS
CT
TE
TOP
VIEW ACTUAL
HOLE
DIAMETER
Page 5
BASIC GEOLOGY WELL PLAN
Formation fracture strength is defined by the overburden stress, cementation, formation pressure and the strength of the rock type.
The following compares the relative strength of the different rock types (all other factors considered equal)
Of the three primary rock types, Sandstone generally exhibits the lowest compressive and tensile strength
Page 6
WELL PLAN BASIC GEOLOGY
NORMAL Formation pressure equal to a full column (surface to depth of interest) of formation water
FORMATION FLUID
.46
5P
SI/
4
FT
5
7
0 1 2 3 4 5
TRANSITION SHALE FORMATION PRESSURE (1000 psi)
Normal formation pressure is calculated: Normal FP = .465 X Vertical Depth
psi ft
Unless better information is known, .465 psi/ft is a safe world-wide average
Formation pressure greater than the normal pressure expected for the depth of
ABNORMAL interest
When permeability drops to near zero, formation fluids become trapped in the pore spaces. Any further compaction
of the formation will pressurize the fluids and produce higher-than-normal (Abnormal) formation pressure
ABNORMAL / SUBNORMAL
FORMATION PRESSURE VERSUS DEPTH
6
NORMAL FP
7
TRANSITION SHALE
ABNORMAL FP
(Permeability Barrier)
NO
8
DEPTH (1000 ft)
RM
AL
FP
9
LIN
E
DEPLETED 10
ZONE SUBNORMAL FP
11
12
3 4 5 6 7 8
FORMATION PRESSURE (1000 psi)
Over geologic time (millions of years), the high pressure pore fluid is squeezed out of the shale to the adjacent
permeable formations (sandstone, limestone, etc.)
Formation pressure less than the normal pressure expected for the depth of interest
SUBNORMAL
Lower-than-normal formation pressure may exist in offshore basins due to production depletion,
however, naturally occurring subnormal pressure is rare. In inland basins, native subnormal
pressure is a common occurrence
Page 7
BASIC GEOLOGY WELL PLAN
RESERVOIR TRAPS
The bed of sediments in which the oil and gas was produced (shale, limestone).
SOURCE ROCK Compaction squeezes the oil and gas to the reservoir rock (primary migration)
RESERVOIR The permeable formation which receives and stores the oil and gas volume of primary
ROCK migration
RESERVOIR The elevation in reservoir rock to which the oil and gas accumulates (secondary migration)
TRAP
STRUCTURAL Traps formed as a result of uplifting, folding and/or faulting of the formation layers
TRAP
The lightest fluid, gas, rises to the top of the trap. The next heaviest fluid, oil, accumulates below the gas and
then the water
GAS
MIGRATION
OIL
SECONDARY
P
M R
IG IM
RESERVOIR WATER R A
A RY
TI
O
N
ROCK
Traps formed by the displacement of the reservoir rock along a stress crack which positions
FAULT TRAP the face of the down-dip section against impermeable rock
DI
SP
SEA LA
LED
FAU
CE
LT P ME
GAS
LANE NT
OIL
WATER
STRATIGRAPHIC Traps formed by a permeable reservoir rock grading to a non-permeable rock or the termination
TRAP of a reservoir rock
SANDSTONE GRADES
TO CLAY
GAS
OIL
WATER
SANDSTONE
PINCH OUT
Page 8
WELL PLAN CASING PROGRAM
SYSTEM FUNCTIONS
FUNCTIONS OF THE CASING SYSTEM
SECTIONS: FUNCTIONS:
Drive or Structural
Casing * PROVIDE HYDRAULIC
INTEGRITY
* Circulation
* Well Control
* Production
Surface Casing
* Fluid Kicks
Intermediate Casing
* Formation Instability
* Incompatible Wellbore
Fluids
PRODUCTION ZONE
PRODUCTION ZONE
SHALE
Page 9
CASING PROGRAM WELL PLAN
ZONE ISOLATION Casing may be set before or deeper than the planned depth to protect
potential production zones
Consolidated. Naturally cemented rock to avoid wash out and/or hole collapse during
SUITABLE cementing
FORMATION
As homogeneous as possible. Interbedded layers of different formation types weaken
the rock and introduce the possibility of permeability
Impermeable. Water loss from the cement slurry can result in flash-setting of the
cement before it is in place
If permeability is present, the true leak-off pressure of the wellbore is difficult to establish
Lowest Rock Strength: Initial fracture gradient assumptions are based on the weakest
rock type
Clean shale is the ideal casing seat formation. In the field, however, the formation selected for the seat is usually the best
compromise between the ideal and what is possible
Surface
Sediments
DATA: FUNCTIONS:
w PIPE SIZES
w Prevent Rig Foundation
9-5/8" - 36" Washout
w Vertical Pilot
STRUCTURAL CASING
(Drilled and Cemented)
w Structural Support
* Conductor casing
w SHUT-IN NOT
RECOMMENDED * Wellhead
* BOP Equipment
Clay Bed
The structural casing is pressure tested, but due to the shallow depth of the seat, the shoe is not tested
Page 10
WELL PLAN CASING PROGRAM
SURFACE CASING
Planned setting depth determined by anticipated hole instability, lost circulation problems
SURFACE CASING and to protect fresh water sands (land based)
Surface casing must provide sufficient fracture strength to allow drilling the next hole interval
with a sufficient kick tolerance
DATA: FUNCTIONS:
w
w EXTEND HYDRAULIC
INTEGRITY
w PIPE SIZE
7" - 20"
w PROTECT FORMATIONS:
w SOLUTION FOR
DRILLING PROBLEMS:
w CASING PRESSURE
TESTED
* Lost Circulation
* Formation Instability
w SHOE PRESSURE
TESTED
w SHUT IN POSSIBLE
SHALE
The casing is pressure tested and the shoe is tested to a maximum anticipated pressure or to leak-off
Page 11
CASING PROGRAM WELL PLAN
INTERMEDIATE CASING
INTERMEDIATE Planned setting depth determined by minimum desired kick tolerance, anticipated hole
CASING instability, lost circulation problems
DATA: FUNCTIONS:
w
w PROVIDE WELL
w PIPE SIZE CONTROL CAPABILITY
5" - 13-3/8"
w SOLUTION FOR
DRILLING PROBLEMS:
* Differential Sticking
w PROTECT FORMATIONS:
w CASING PRESSURE
TESTED * Low / High Wellbore
Pressure
* Incompatible Wellbore
Fluids
w SHOE PRESSURE
TESTED
* Production Zone Isolation
w SHUT-IN RECOMMENDED
(Set In Pressure
Transition Shale)
TRANSITION ZONE
SHALE
The casing is pressure tested and the shoe tested to a maximum anticipated pressure or to leak-off
Page 12
WELL PLAN CASING PROGRAM
DRILLING LINER
DRILLING LINER Planned setting depth determined by minimum desired kick tolerance, anticipated hole
instability, lost circulation problems or protecting production zones
If the liner is contingent on drilling problems, occurrence of the problem determines the
setting depth
DATA: FUNCTIONS:
w
w PROVIDE WELL
CONTROL CAPABILITY
w PIPE SIZE
5" - 11-3/4" w SOLUTION FOR SPECIFIC
DRILLING PROBLEMS:
* Lost circulation
w PROTECT FORMATIONS:
* Incompatible Wellbore
Fluids
The liner is pressure tested and the shoe and liner top tested to a maximum anticipated pressure or to leak-off
Page 13
CASING PROGRAM WELL PLAN
DATA: FUNCTIONS:
w
w PROVIDE WELL
w PIPE SIZE CONTROL CAPABILITY
5" - 9-5/8"
w PROVIDE A STABLE
WELLBORE:
w CEMENTED BACK
TO PREDETERMINED * Well Testing
DEPTH
* Production Operations
w PRODUCTION ZONE
ISOLATION:
* Selective Testing
* Dual Completions
Production Zone
Production Zone
Shale
The casing, tie-back casing, liner and top are tested to a maximum anticipated pressure
Page 14
WELL PLAN DRILLING FLUIDS
DRILLING FLUID A fluid used to perform various functions during a drilling operation
TRANSMIT HYDRAULIC Base fluid of the mud Remove cuttings from below bit
HORSEPOWER TO BIT face to improve penetration rate
INHIBITIVE (SALTS) Drilling water sensitive shales Controls chemical reaction of shales
POLYMERS Improved penetration rate
Page 15
DRILLING FLUIDS WELL PLAN
WELL CONTROL Seismic data evaluations The mud system must be capable of minimum to
REQUIREMENTS Offset well data maximum mud weight requirements
Field experience
Mud company records
HOLE STABILITY Seismic data evaluations An inhibited system is selected to avoid chemical
Chemical / Mechanical Offset well data reaction with water sensitive shales and water
Field experience soluble formations (salt, anhydrite)
Mud company records
TEMPERATURE/ Offset well data The mud system must tolerate formation
CHEMICAL STABILITY Field experience temperatures without chemical break down
OF THE MUD Mud company records
Must tolerate contamination from formation fluids,
minerals and solids
OPTIMUM DRILLING Offset well data The mud system should provide an acceptable
AND ECONOMIC Field experience penetration rate with minimum formation damage
PERFORMANCE Mud company records at the lowest cost
Bit company records
BASE FLUID / MUD Offset well data May limit the choice of mud systems in remote
PRODUCT AVAILABILITY Mud company records areas
RIG EQUIPMENT Contractor inventory May limit the choice of mud systems in remote
Field experience areas
Page 16
WELL PLAN DRILLING FLUIDS
CONTAMINANT EXAMPLE
Page 17
DRILLING FLUIDS WELL PLAN
Reactive shale drilled, Drill solids increase, Low water content, Calcium
INCREASE contamination from cement, Anhydrite formation drilled
FUNNEL
VISCOSITY
DECREASE Formation water influx, Excessive water content
Page 18
WELL PLAN DRILLING FLUIDS
OIL / WATER Large addition of water or water influx, Large additions of base oil, High
CHANGE
RATIO bottom hole temperature
Page 19
HYDRAULICS PLANNING WELL PLAN
GEOLOGY
The calculated balance of the hydraulic components that will sufficiently clean
HYDRAULICS OPTIMIZATION the bit and wellbore with minimum horsepower
MAXIMIZE In soft formations and high angle holes, maximize flow rate for hole cleaning
HOLE CLEANING
In small and/or deep holes, limit flow rate to minimize annulus friction pressure
ANNULUS and reduce the potential for:
FRICTION PRESSURE
Lost Circulation; Differential Sticking; Hole Instability
BIT PLUGGING Larger jet sizes may be required if there is potential for lost circulation
Page 20
WELL PLAN HYDRAULICS PLANNING
Too low a flow rate will "ball" the bit and reduce effective hole cleaning
Too high a flow rate increases ECD and erodes soft or unconsolidated zones
Slow drilling with mud requires a minimum of 30 GPM per inch of bit diameter
Fast drilling with low mud weights requires 50+ GPM per inch of bit diameter
Do not waste fuel and wear on the pumps with excessive pressure
2
Many rigs do not have enough horsepower to provide the recommended HHP/In
BIT PRESSURE DROP Design hydraulics for 50% to 65% pressure drop across the bit
Nozzle velocity (ft/sec) - The velocity of the fluid exiting the bit jets
35% to 50% of pump pressure is lost through the drill string and annulus. Hydraulic calculations are required to
determine these losses
If the total of drill string and annular pressure loss is greater than 50% of the available pump pressure, Jet Velocity
optimization is required. However, do not operate below 30 GPM per inch of bit diameter
JET VELOCITY Maintain jet velocity between 350 and 450 feet per second
Impact Force - The product of fluid jet velocity and fluid weight. Impact is the force the drilling fluid exerts to the
formation to assist bottom hole cleaning
For small holes (9-1/2" and smaller) and slow drilling, consider running 2 jets versus 3 to improve bottom hole cleaning
and penetration rate. Two large jets are less likely to plug than 3 small jets (same total flow area, TFA)
If a long hole section is planned for the next bit, consider running 3 jets and dropping a diverting ball in the lower part
of the hole section to maintain jet velocity
Asymetrical jets are often run to improve penetration rate versus using two jets
Page 21
HOLE PROBLEMS STUCK PIPE
RESERVOIR TRAPS
DEFINITIONS
STUCK PIPE Planned operations are suspended when down hole force(s) prevent pulling the string out of the hole
TIGHT HOLE Down hole force(s) restrict string movement above normal operating conditions (a usual warning indicator
of a stuck pipe event)
MECHANISMS
STUCK PIPE MECHANISMS
HOLE PACK-OFF/BRIDGE DIFFERENTIAL STICKING WELLBORE GEOMETRY
UNCONSOLIDATED
MICRO DOGLEGS
FORMATIONS
FRACTURED LEDGES
FORMATIONS
CEMENT RELATED MOBILE FORMATIONS
CAUSES
HOLE PACK-OFF / BRIDGE MECHANISM
HOLE PACK-OFF: Formation solids (cuttings, cavings) settle around the drill string and pack off
the annulus resulting in stuck pipe
HOLE BRIDGE: Medium to large pieces of hard formation, cement or junk falls into the wellbore
and jams the drill string resulting in stuck pipe
JUNK
Page 22
HOLE PACK-OFF STUCK PIPE HOLE PROBLEMS
HOLE ANGLE
Reduces the ability to clean the hole
CAUSE:
DRILLED CUTTINGS ARE NOT TRANSPORTED
OUT OF THE HOLE DUE TO LOW ANNULAR
VELOCITY AND/OR POOR MUD PROPERTIES
WHEN CIRCULATION IS STOPPED, THE
CUTTINGS FALL BACK DOWN THE HOLE AND
PACK-OFF THE DRILL STRING
S
T
R
IN
WARNING:
G
RO T
BREAK CIRCULATION
FILL ON BOTTOM
INDICATIONS:
LIKELY TO OCCUR ON CONNECTIONS,
POSSIBLE DURING TRIP
CIRCULATION RESTRICTED OR IMPOSSIBLE
OVERP
FIRST ACTION:
APPLY LOW PUMP PRESSURE (200 - 400 psi)
ULL!!
Page 23
HOLE PROBLEMS STUCK PIPE HOLE PACK-OFF
CAUSE:
DRILL CUTTINGS SETTLE ON THE LOW SIDE
OF THE HOLE AND FORMS A CUTTINGS BED
THE CUTTINGS BED BUILDS AND SLIDES
DOWN HOLE PACKING OFF THE DRILL
STRING
WHILE POOH, THE CUTTINGS BED IS
DRAGGED UPWARD BY THE BHA AND PACKS
OFF THE DRILL STRING
WARNING:
HOLE ANGLE GREATER THAN 35
CIR
CU
LA
TI
O
N
INDICATIONS:
LIKELY TO OCCUR WHILE POOH, POSSIBLE
WHILE DRILLING
CIRCULATING PRESSURE RESTRICTED OR
OV
IMPOSSIBLE
ER
PU
FIRST ACTION:
LL
PREVENTIVE ACTION:
RECORD TREND INDICATORS FOR
CUTTINGS INADEQUATE HOLE CLEANING
BED
CONTROL ROP, MAINTAIN MUD PROPERTIES,
CIRCULATE AT MAXIMUM RATE, MAXIMIZE
PACK STRING ROTATION
OFF!!
CIRCULATE HOLE CLEAN BEFORE POOH,
ESTABLISH AN OVERPULL LIMIT
Page 24
STUCK PIPE
HOLE PACK-OFF HOLE PROBLEMS
PREVENTIVE ACTION
Maintain the required mud properties
Place more emphasis on annular velocity when designing the hydraulics for 12-1/4" and larger hole sizes. Consider using a
riser booster line when drilling 8-1/2" and smaller hole sizes
Do not allow the penetration rate to exceed the ability to clean the hole
Record torque and drag trends for symptoms of inadequate hole cleaning
Consider a wiper trip after drilling a long section with a down hole motor
Wipe the hole at full circulating rate as long as possible (5 - 10 min) before connections, Rotate at maximum RPM when possible
Maximize string motion when circulating the hole clean. Use maximum practical RPM, raise the drill string slowly (5 min/std) and
slack-off at a safe but fast rate (1 min/std)
Consider pumping high-vis sweeps in low angle wells (<35 ). Consider low-vis / high-vis sweeps in higher angle wells (>35 )
Circulate until the hole is clean, If the last sweep brings up excessive amounts of cuttings, continue with hole cleaning operations,
Several circulations may be necessary
Page 25
HOLE PROBLEMS STUCK PIPE HOLE PACK-OFF
MINIMUM GPM
MINIMUM GPM VERSUS HOLE SIZE AND HOLE ANGLE
HOLE SIZE 26" 17-1/2"- 16" 12-1/4" 8-1/2"
ANGLE INTERVAL
0 - 35 700 GPM 500 GPM 400 GPM 300 GPM
Minimum flow rate (GPM) for any given hole size and angle is greatly dependent on mud weight, mud
rheology and annulus geometry. Maximum recommended flowrate is 60 GPM per inch of bit diameter
MINIMUM ROP
MAXIMUM ROP VERSUS HOLE SIZE AND HOLE ANGLE
HOLE SIZE 26" 17-1/2"- 16" 12-1/4" 8-1/2"
ANGLE INTERVAL
0 - 35 60 110 155 240
35 - 55 40 75 85 125
55 + 60 75 100
Penetration rate guidelines are based on adequate mud properties
MINIMUM STROKES
MINIMUM CIRCULATING STROKES FACTOR (CSF) TO CLEAN HOLE
HOLE SIZE 26" 17-1/2"- 16" 12-1/4" 8-1/2"
ANGLE INTERVAL
0 - 35 2 1.7 1.4 1.4
55 + 3 2 1.7
PROCEDURE:
1. Separate the wellbore into sections by hole angle from intervals above.
2. Multiply each hole section length (Sect. Lth) by CSF and total the adjusted measured depth (MD).
Adjusted MD = (Sect. Lth X CSF) + (Sect. Lth X CSF) + (Sect. Lth X CSF)
Page 26
HOLE PACK-OFF
STUCK PIPE HOLE PROBLEMS
EXAMPLE CALCULATION
MINIMUM CIRCULATING STROKES CALCULATION (12-1/4" HOLE)
SEPARATE THE WELLBORE INTO SECTIONS BY HOLE ANGLE INTERVALS
o o o o o
0 To 35 35 To 55 55 +
0' To 4500' = 4500' 4500' To 6500' = 2000' 6500' To 13,000' = 6500'
o o
0 To 35
0' To 4500'
o o
35 To 55
4500' To 6500'
o
55 +
6500' To 13,000'
Page 27
HOLE PROBLEMS
STUCK PIPE HOLE PACK-OFF
DRILLING
Maintain sufficient mud weight to stabilize the wellbore as hole angle and/or formation pressure increases
.
Use proper Low-End-Rheology for hole size and angle to maximize hole cleaning
.
Circulate at maximum rate for hole size and hole angle
.
Limit the ROP to the maximum recommended for hole size and hole angle
.
Back ream each stand (or 1/2 stand) drilled with a down-hole motor
.
Rotate at high RPM (160+). Raise the drill string slowly (i.e., 5 min/stand). Lower the drill string
at a safe but fast rate (i.e., 1 min/stand)
.
Continue back reaming if hole conditions dictate
.
Consider a wiper trip after drilling a long section with a down hole motor to mechanically agitate
and remove cuttings bed
.
Pump a sweep (pill) if hole conditions do not improve. Consider low-vis / high-density tandem sweeps. Optimize sweep type,
volume and frequency pumped
..
Consider reducing ROP or stop drilling and circulate until hole conditions improve
CONNECTIONS
Start and stop drill string slowly. Ensure adequate back reaming at full circulation rate prior to connections
.
Prepare crew and equipment to minimize connection time
.
Record free rotating weight, pick-up weight, slack-off weight, off-bottom torque, and circulating pressure for trend indications of
inadequate hole cleaning
.
Pull the slips and slowly rotate the drill string first, then increase pump speed slowly. Carefully lower the drill string to bottom
TRIPPING
.
Circulate 1 to 3 joints off bottom while cleaning the hole to avoid dropping bottom hole angle. Consider sweeps (pills) to aid hole
cleaning
.
Rotate at high RPM (160+) while cleaning the hole. Raise the drill string slowly (i.e., 5 min/stand), lower the drill string at a safe
but fast rate (i.e., 1 min/stand)
.
Ensure recommended minimum circulation strokes for hole size and angle are pumped, 2 to 4 times normal bottoms-up may be
required. Circulate until the shakers are clean
.
Consider pumping a sweep (pill) to determine if additional circulation time is required.
.
Inform the Driller of the measured depth and stand count when the top of the BHA reaches the deepest anticipated cuttings bed.
Maximum cuttings bed thickness is likely between 45 and 65 hole angle
.
Determine an overpull limit prior to pulling out of the hole (the lesser of 1\2 BHA weight or 30,000 lbs)
.
If overpull limit occurs, run in 1 stand and repeat hole cleaning guidelines from present bit depth. When the shakers are clean,
continue pulling out of the hole. If the overpull limit is again reached, repeat procedure
Page 28
HOLE PACK-OFF
STUCK PIPE HOLE PROBLEMS
SHALE INSTABILITY
The shale formation becomes unstable, breaks apart and falls into the wellbore
SHALE
BREAKING CAUSE:
APART 1 DAY EXPOSURE
WATER SENSITIVE SHALE DRILLED WITH LITTLE
WATER OR NO MUD INHIBITION
ABSORBED SHALE ABSORBS WATER AND SWELLS INTO
THE WELLBORE
BY SHALE
REACTION IS TIME DEPENDENT
WARNING:
HOLE
WALL FUNNEL VISCOSITY, PV, YP, CEC INCREASE
TORQUE & DRAG INCREASE
PUMP PRESSURE INCREASE
CLAY BALLS AND/OR SOFT "MUSHY" CUTTINGS
AT SHAKER
INDICATIONS:
GENERALLY OCCURS WHILE POOH, POSSIBLE
WHILE DRILLING
CIRCULATION IMPOSSIBLE OR HIGHLY
RESTRICTED
FIRST ACTION:
PA
OF CK ! PREVENTIVE ACTION:
F!! CK!
STU USE AN INHIBITED MUD
MAINTAIN MUD PROPERTIES
PLAN WIPER TRIPS
MINIMIZE HOLE EXPOSURE TIME
Page 29
HOLE PROBLEMS STUCK PIPE HOLE PACK-OFF
PREVENTIVE ACTION
Addition of various salts (potassium, sodium, calcium, etc.) to reduce the chemical attraction of water to the shale
Addition of various encapsulating (coating) polymers to reduce water contact with the shale
Use of oil and synthetic base muds to exclude water contact with the shale
Plan regular wiper / reaming trips based on time, footage drilled or the warning signs of reactive shale
Page 30
HOLE PACK-OFF
STUCK PIPE HOLE PROBLEMS
CAUSE:
.
DRILLING PRESSURED SHALE WITH
HYDROSTATIC INSUFFICIENT MUD WEIGHT
FORMATION PRESSURE 5500 .
PRESSURE 5000 PSI PSI THE STRESSED SHALE FRACTURES AND
CAVES INTO THE WELLBORE
WARNING:
5000 SIGNS BEGIN TO OCCUR AS SHALE IS DRILLED
PSI 5500 PSI
STRESS!!
Pore
HSP
Pressure MUD LOGGER TRENDS INDICATE INCREASING
Str
ess Crack PORE PRESSURE
INDICATIONS:
FIRST ACTION:
PA
OF CK APPLY LOW PUMP PRESSURE (200 - 400 psi)
F!
! APPLY TORQUE, JAR DOWN WITH MAXIMUM
TRIP LOAD
CK!!
STU PREVENTIVE ACTION:
ADJUST MUD WEIGHT BEFORE DRILLING
KNOWN PRESSURED SHALE
Page 31
HOLE PROBLEMS
STUCK PIPE HOLE PACK-OFF
CAUSE:
WARNING:
GENERALLY FOLLOWS A MUD WEIGHT
REDUCTION
TORQUE & DRAG INCREASE
DAYS OF EXPOSURE SHALE CAVINGS AT SHAKER
0 2 4 6 8
UNSTABILIZED
SHALE INDICATIONS:
POSSIBLE WHILE DRILLING OR TRIPPING
FIRST ACTION:
CIRCULATION IS ESTABLISHED
PREVENTIVE ACTION:
USE OBM, SBM OR GLYCOL BASE MUD IF
PROBLEM IS SUSPECTED
PAC
OFF K
!! ! IF A MUD WEIGHT REDUCTION IS NECESSARY,
!
U CK REDUCE GRADUALLY OVER SEVERAL
CIRCULATIONS
ST
MINIMIZE WELLBORE PRESSURE SURGES
Page 32
HOLE PACK-OFF STUCK PIPE HOLE PROBLEMS
CAUSE:
MUD WEIGHT IS INSUFFICIENT TO SUPPORT
BURDEN
THE OVER BURDEN
over
MUD WT. MUD WEIGHT IS NOT ADJUSTED AS HOLE
12.5 PPG
ANGLE INCREASES
0
STABILIZED
90 STRESSED SHALE FRACTURES AND FALLS
HSP SHALE 12.0 PPGE STRESS INTO THE WELLBORE
E ST
G RE 45
PP
0
SS WARNING:
.0
13 HOLE CLEANING PROBLEMS
0
0
20
0
INCREASE TORQUE & DRAG
00
14.0 SHALE CAVINGS AT SHAKER
PPGE
INDICATION:
CAN OCCUR WHILE DRILLING OR TRIPPING
RESTRICTED CIRCULATION OR NO
CIRCULATION POSSIBLE
FIRST ACTION:
Page 33
HOLE PACK-OFF
STUCK PIPE HOLE PROBLEMS
CAUSE:
STRESS!!
WARNING:
TECTONIC
MOUNTAINOUS LOCATION
PROGNOSED TECTONICS
INDICATIONS:
POSSIBLE WHILE DRILLING OR TRIPPING
SHALE CIRCULATION RESTRICTED OR IMPOSSIBLE
CAVING IN
OVER PULL!!
FIRST ACTION:
PREVENTIVE ACTION:
!!
SAN DSTONE INCREASE MUD WEIGHT IF POSSIBLE
BRID STU
GING CK!!
!!
Page 34
STUCK PIPE
HOLE PROBLEMS HOLE PACK-OFF
PREVENTIVE ACTION
Consider offset well data and/or computer models which simulate shale failure limits when planning the mud weight for each
hole section
Mud weight increase with hole angle and TVD specific to the area to maintain hole stability
Exploration wells, consult the Mud Logger for changes in formation pressure. Increase the mud weight cautiously until
symptoms are no longer observed
If possible, increase mud weight slowly (0.1 to 0.2 ppg per day) until the desired density for a given depth is reached. This will
maintain an overbalance against hydrostatically sensitive shales
AVOID MUD WEIGHT REDUCTION after 1+ day exposure to hydrostatically sensitive shale. If mud weight reduction is necessary,
reduce the mud weight gradually over a time frame equal to the time of exposure
Use the Shaker Handover Notes to determine trends of cuttings volume, size and shape
Page 35
HOLE PROBLEMS
STUCK PIPE HOLE PACK-OFF BRIDGE
UNCONSOLIDATED FORMATION
CAUSE:
LITTLE OR NO FILTER CAKE
WARNING:
LIKELY TO OCCUR AS THE FORMATION IS
DRILLED
SEEPAGE LOSS LIKELY
INDICATIONS:
GENERALLY OCCURS IN SURFACE HOLE
CIRCULATION IMPOSSIBLE
FIRST ACTION:
APPLY LOW PUMP PRESSURE (200 - 400 psi)
PREVENTIVE ACTION:
CONTROL FLUID LOSS TO PROVIDE AN
ADEQUATE FILTER CAKE
CK!!
PACK STU CONTROL DRILL SUSPECTED ZONE
OFF!!
USE HIGH VIS SWEEPS
Page 36
HOLE PACK-OFF / BRIDGE STUCK PIPE HOLE PROBLEMS
Hole fill
Overpull off slips Surge to start
CONNECTION circulation
PREVENTIVE ACTION
Provide an effective filter cake for the hydrostatic overbalance to "push against" and stabilize the formation
If possible, avoid excessive circulating time with the BHA opposite unconsolidated formations to reduce hydraulic erosion
Slow down tripping speed when the BHA is opposite unconsolidated formations to avoid mechanical damage
Start and stop the drill string slowly to avoid pressure surges to unconsolidated formations
Control-drill the suspected zone to allow time for filter cake build up, minimize annulus loading and to minimize annulus friction
pressure
Minimize seepage loss with fine lost circulation material through these intervals
Page 37
HOLE PROBLEMS STUCK PIPE HOLE PACK-OFF / BRIDGE
FRACTURED FORMATION
CAUSE:
WARNING:
INDICATIONS:
FIRST ACTION:
BRID
GED! DO NOT APPLY TORQUE, JAR DOWN WITH
! MAXIMUM TRIP LOAD
FRACTURED
K!
LIMESTONE
UC
ST
PREVENTIVE ACTION:
CIRCULATE HOLE CLEAN BEFORE DRILLING
AHEAD
Page 38
HOLE PACK-OFF / BRIDGE STUCK PIPE HOLE PROBLEMS
MUD No change
TRENDS
PREVENTIVE ACTION
NOTE: With fractured formations, maintaining a good quality filter cake can help to support the formation in some cases. Generally,
fractured formations require time to stabilize. Prior to this, the problem must be controlled with adequate mud properties, sweeps
and sufficient circulation time to keep the hole clean, Other recommendations:
Restrict tripping speed when BHA is opposite fractured formations and fault zones
Start / stop the drill string slowly to avoid pressure surges to the wellbore
Be prepared for the potential of lost circulation when drilling fractured formations
Page 39
HOLE PROBLEMS STUCK PIPE HOLE PACK-OFF / BRIDGE
CEMENT BLOCKS
CAUSE:
WARNING:
EXCESSIVE CASING RATHOLE
OVER PULL!!
INDICATIONS:
CIRCULATION POSSIBLE
FIRST ACTION:
BRID
GED! !! PREVENTIVE ACTION:
!
UCK MINIMIZE CASING RATHOLE
ST ALLOW SUFFICIENT CURING TIME
Page 40
HOLE PACK-OFF / BRIDGE STUCK PIPE HOLE PROBLEMS
SOFT CEMENT
CAUSE:
CIRCULATION IS ATTEMPTED WITH THE
BOTTOM OF THE DRILL STRING IN SOFT
SET DOWN!!
CEMENT
PUMP PRESSURE CAUSES THE CEMENT TO
FLASH SET
INDICATIONS:
OCCURS AS PUMP PRESSURE IS APPLIED
FIRST ACTION:
FLASH
PUMP SET!! BLEED TRAPPED PUMP PRESSURE
PRESSURE
JAR UP WITH MAXIMUM TRIP LOAD
PREVENTIVE ACTION:
KNOW CEMENT SET TIME
!
CK!
STU
FIRM
CEMENT
Page 41
HOLE PROBLEMS STUCK PIPE HOLE PACK-OFF / BRIDGE
JUNK
CAUSE:
POOR HOUSE KEEPING ON THE FLOOR, HOLE
COVER NOT INSTALLED
WARNING:
JUNK STICKING CAN OCCUR AT ANY TIME
DURING ANY OPERATION
METAL SHAVINGS AT SHAKER
INDICATIONS:
GENERALLY OCCURS WHEN BHA IS IN HARD
FORMATION OR INSIDE THE CASING
FIRST ACTION:
IF MOVING UP WHEN STICKING OCCURRED,
JAR DOWN WITH MAXIMUM TRIP LOAD
!!
U CK
S T PREVENTIVE ACTION:
GOOD HOUSE KEEPING ON FLOOR
Page 42
HOLE PACK-OFF / BRIDGE
STUCK PIPE HOLE PROBLEMS
CEMENT BLOCKS
PREVENTIVE ACTION
Several squeeze jobs at the casing shoe increases the potential for cement blocks
Ream casing ratholes and open hole cement plugs slowly and thoroughly before drilling ahead
Maintain sufficient distance between the paths of platform wells to reduce the possibility of cement blocks
Reduce tripping speed when BHA is entering the casing shoe or opposite open hole cement plugs
Start and stop the drill string slowly to avoid pressure surges to the wellbore
SOFT CEMENT
PREVENTIVE ACTION
Know the calculated top of cement (TOC) before tripping in hole
Do not rely on the weight indicator to find the top of the cement
Begin washing down 2 stands above the theoretical top of the cement
If set down weight is observed when tripping in hole after a cement operation, set back 2 stands before attempting
circulation
Pre-treat the mud system with chemical prior to drilling out cement
Verify cement compressive strength with cement company before drilling out
JUNK
PREVENTIVE ACTION
Inspect slip and tong dies regularly
Page 43
HOLE PROBLEMS STUCK PIPE DIFFERENTIAL STICKING
DIFFERENTIAL STICKING
A sticking force developed when differential pressure (overbalance) forces a stationary drill string into the thick filter cake of a
permeable zone
. SANDSTONE FILTER
PERMEABLE 4000 PSI CAKE
FORMATION .
. NO FILTER
FILTER CAKE
A cake of mud solids
Sandstone / CAKE develops on the hole wall
fractured limestone due to fluid loss
.
HYDROSTATIC High fluid loss increases
PRESSURE (HSP) filter cake thickness
.
OVER 5000 PSI Thick filter cake increases
sticking potential
.
BALANCE
HIGH
FLUID LOSS
CONTROLLED
FLUID LOSS
Wellbore pressure greater
than formation pressure
LOW TIME
PRESSURE DEPENDENT
AREA
With time, the area of pipe
. sealed in the filter cake
An area of low HSP increases
pressure develops FP
between the pipe & filter 5000 4" 4000 Immediate action is
cake required to free the drill
.
PSI PSI string
Overbalance pressure
across the contact area
determines the differential LOW PRESSURE
force AREA
Page 44
DIFFERENTIAL STICKING
STUCK PIPE HOLE PROBLEMS
DIFFERENTIAL STICKING
TOP CAUSE:
STATIC VIEW .
FILTER DRILL STRING CONTACTS A PERMEABLE ZONE
CAKE .
WHEN STRING MOVEMENT STOPS, A STATIC
FILTER CAKE DEVELOPS
.
HIGH OVERBALANCE APPLIES A DIFFERENTIAL
FORMATION HSP STICKING FORCE TO THE DRILL STRING
PRESSURE 4" 5000 CONTACT AREA
4000 psi PSI
WARNING:
LOW .
PRESSURE PROGNOSED LOW PRESSURE SANDS
AREA .
LONG /UNSTABILIZED BHA SECTIONS
.
INCREASING OVER PULL, SLACK OFF WEIGHT OR
TORQUE TO START STRING MOVEMENT
INDICATIONS:
SIDE .
OVER PULL!!
1200 Sq In
.
APPLY TORQUE AND JAR DOWN
STU Contact WITH MAXIMUM TRIP LOAD
Area .
CK SPOT A PIPE RELEASING PILL IF
!! THE STRING DOES NOT JAR FREE
Page 45
HOLE PROBLEMS
STUCK PIPE DIFFERENTIAL STICKING
PREVENTIVE ACTION
Design the casing program to minimize overbalance to shallower open hole formations
Limit mud weight to minimum required for hole stability and well control
KEEP THE STRING MOVING. Consider rotating the string during drilling and tripping connections while BHA is opposite
potential sticking zones
Preplan to minimize the down time for operations that require the sticking remaining static (surveys, minor repairs, etc.).
In zones with high sticking potential, minimize seepage loss with plugging agents
Keep a pipe releasing pill ready at the well site when differential stricking potential is high
Page 46
WELLBORE GEOMETRY
STUCK PIPE HOLE PROBLEMS
WELLBORE GEOMETRY
Hole diameter and/or angle relative to BHA geometry and/or stiffness will not allow passage of the drill string
BHA CHANGE
STIFF ASSEMBLY
CAUSE:
.
BECOMES JAMMED
WARNING:
.
DOGLEGS PRESENT
POOH WITH
LIMBER BHA .
INDICATIONS:
.
DEPTH
FIRST ACTION:
.
PREVENTIVE ACTION:
.
RIH WITH MINIMIZE BHA CHANGES, CONSIDER
STIFF BHA A REAMING TRIP
STUCK!! LIMIT DOGLEG SEVERITY
.
SLOW TRIP SPEED BEFORE BHA
ENTERS SUSPECTED ZONE, PLAN TO
REAM
LIMIT SET DOWN WEIGHT
Page 47
STUCK PIPE WELLBORE GEOMETRY
HOLE PROBLEMS DIRECTION / ANGLE CHANGE
KEY SEAT
N
CAUSES:
IO
.
NS
TE ABRUPT CHANGE IN ANGLE OR DIRECTION
IN MEDIUM SOFT TO MEDIUM HARD
TOOLJOINT
FORMATION
.
RO
TA
TI ON
OD HIGH STRING TENSION AND PIPE
ROTATION WEARS A SLOT INTO THE
FORMATION
SIDE LOAD .
WHILE POOH, THE DRILL COLLARS JAM
INTO THE SLOT
WARNING:
.
HIGH ANGLE DOGLEG IN UPPER HOLE
W
SECTION
EI
GH
.
T
INDICATIONS:
SLOT WORN INTO
FORMATION
.
OCCURS ONLY WHILE POOH
.
SUDDEN OVER PULL AS BHA REACHES
DOGLEG DEPTH
.
UNRESTRICTED CIRCULATION
.
FREE STRING MOVEMENT BELOW KEY
SEAT DEPTH POSSIBLE IF NOT STUCK
FIRST ACTION:
.
APPLY TORQUE AND JAR DOWN WITH
MAXIMUM TRIP LOAD
ULL!!
PREVENTIVE ACTION:
BHA .
MINIMIZE DOGLEG SEVERITY TO 3 /100' OR
O
!!
U
C
K
LESS
ST .
LIMIT OVERPULLS THROUGH SUSPECTED
INTERVALS
.
PLAN REAMER AND/OR WIPER TRIPS IF A
DOGLEG IS PRESENT
.
RUN STRING REAMER OR KEY SEAT WIPER
IF SUSPECTED
Page 48
WELLBORE GEOMETRY STUCK PIPE
DIRECTION / ANGLE CHANGE HOLE PROBLEMS
MICRO DOGLEGS
CAUSES:
.
HARD/SOFT INTERBEDDED FORMATIONS
OVER PULL!! .
FREQUENT CORRECTIONS IN HOLE ANGLE OR
DIRECTION
.
BHA BECOMES JAMMED IN THE SUCCESSIVE
MICRO DOGLEGS
K !! WARNING:
UC .
ST PROGNOSED HARD/SOFT INTERBEDDED
FORMATIONS
.
FREQUENT ANGLE/DIRECTION CHANGES
.
DRILLING/SLIDING WITH DOWN HOLE MOTOR
.
ERRATIC TORQUE AND DRAG ON CONNECTION
INDICATIONS:
G .
DRA LIKELY WHEN PICKING UP FOR A CONNECTION,
POSSIBLE ON TRIPS
.
CIRCULATION UNRESTRICTED
FIRST ACTION:
.
IF MOVING UP WHEN STICKING OCCURRED,
APPLY TORQUE AND JAR UP WITH MAXIMUM
TRIP LOAD
.
DRAG IF MOVING DOWN, JAR UP WITH MAXIMUM TRIP
LOAD, DO NOT APPLY TORQUE
PREVENTIVE ACTION:
! .
K! MINIMIZE BHA CHANGES
UC
ST MINIMIZE DIRECTION / ANGLE CHANGES
.
BACKREAM FREQUENTLY WHEN DRILLING
HARD/SOFT FORMATIONS
.
SLOW TRIP SPEED BEFORE BHA ENTERS
SUSPECTED ZONE
Page 49
STUCK PIPE WELLBORE GEOMETRY
HOLE PROBLEMS DIRECTION / ANGLE CHANGE
LEDGES
SOFT
FORMATION CAUSES:
.
INTERBEDDED FORMATIONS.
SOFT ROCKS - WASH OUT
HARD ROCKS - IN GAUGE
.
OVER PULL!!
FIRST ACTION:
.
STUCK!! IF MOVING UP WHEN STICKING OCCURRED,
APPLY TORQUE AND JAR DOWN WITH
MAXIMUM TRIP LOAD
.
IF MOVING DOWN, JAR UP WITH MAXIMUM
G TRIP LOAD. DO NOT APPLY TORQUE
A
DR
PREVENTIVE ACTION:
.
MINIMIZE DIRECTION / ANGLE CHANGES
MINIMIZE BHA CHANGES
PLAN REAMING TRIPS, REAM WITH CAUTION
SLOW TRIP SPEED BEFORE BHA ENTERS
SUSPECTED ZONE
Page 50
WELLBORE GEOMETRY STUCK PIPE
HOLE DIAMETER DECREASE HOLE PROBLEMS
MOBILE FORMATION
CAUSES:
.
OVER BURDEN WEIGHT SQUEEZES PLASTIC
SALT OR SHALE INTO THE WELLBORE
.
THE BHA BECOMES JAMMED IN THE UNDER
GAUGE HOLE
FORMATION
FORMATION
WARNING:
WEIGHT
WEIGHT
PROGNOSED SALT OR PLASTIC SHALE
.
SUDDEN INCREASE IN OVER PULL OR SET
DOWN WEIGHT
.
SUDDEN TORQUE INCREASE WITH FAST
MOVING PLASTIC FORMATION
INDICATIONS:
.
GENERALLY OCCURS WHILE POOH
PLASTIC SALT
POSSIBLE WHEN RIH AFTER A LONG PERIOD
OR SHALE OUT OF THE HOLE
OVER PULL!!
.
POSSIBLE WHILE DRILLING IF FORMATION
MOVES FAST
SQUEEZING .
SQUEEZING
FORCE STICKING OCCURS WITH BHA AT PLASTIC
FORCE
ZONE DEPTH
.
CIRCULATION UNRESTRICTED OR SLIGHT
RESTRICTION POSSIBLE
FIRST ACTION:
.
IF MOVING UP, APPLY TORQUE AND JAR DOWN
!
CK!
WITH MAXIMUM TRIP LOAD
STU
.
STU IF MOVING DOWN, JAR UP WITH MAXIMUM TRIP
CK! LOAD. DO NOT APPLY TORQUE
! .
SPOT FRESH WATER IF IN SALT. (CONSIDER
WELL CONTROL)
PREVENTIVE ACTION:
.
SELECT THE CORRECT MUD SYSTEM
Page 51
STUCK PIPE WELLBORE GEOMETRY
HOLE PROBLEMS HOLE DIAMETER DECREASE
UNDERGAUGE HOLE
CAUSES:
.
DRILLING HARD ABRASIVE ROCK WEARS BIT
GAUGE PROTECTION
.
CORED HOLE SECTION UNDER GAUGE
.
NEW BIT IS JAMMED INTO THE UNDER GAUGE
HOLE SECTION
ABRASIVE
WARNING:
SANDSTONE
.
PROGNOSED ABRASIVE SANDS
.
PULLED BIT AND STABILIZERS ARE UNDER
GAUGE
INDICATIONS:
.
OCCURS ONLY WHEN RIH
.
SUDDEN SET DOWN WEIGHT
.
BIT STUCK NEAR BOTTOM OR AT TOP OF CORE
HOLE SECTION
.
CIRCULATION UNRESTRICTED OR SLIGHTLY
SET DOWN
WEIGHT!!
RESTRICTED
FIRST ACTION:
.
JAR UP WITH MAXIMUM TRIP LOAD. DO NOT
APPLY TORQUE
ST
UC PREVENTIVE ACTION:
K! .
! GAUGE PULLED BIT AND STABILIZERS
.
NEVER FORCE BIT THROUGH TIGHT SPOTS
Page 52
STUCK PIPE
WELLBORE GEOMETRY HOLE PROBLEMS
The indications of Wellbore Geometry problems are observed only when BHA is movin in the hole section with the
geometry problem.
DRILLER INDICATIONS OF WELLBORE GEOMETRY PROBLEMS
TRENDS DRAG TORQUE PRESSURE OTHER
Increasing, erratic Increasing, No change Momentary over pull &
DRILLING erratic set down
Increasing, erratic Surge to start Momentary over pull &
CONNECTION set down
circulation
PREVENTIVE ACTION
Optimize BHA design (run only what is required) and when possible, minimize BHA stiffness
Plan a reaming trip if the new BHA is locked up and/or a hole geometry problem is suspected
Slow down trip speed before BHA enters kick off or doglegs depth, depth of micro dogleg and/or ledges, mobile formation depth
o
Minimize dogleg severity to 3 /100' or less. Minimize rotating hours below a sharp dogleg without a wiper or reaming trip
Consider using key seat wipers or drill string reamers if a key seat is suspected
Limit the length of casing rathole to avoid key seating the bottom of the casing. Do not start angle building operations too close to
the shoe
Avoid prolonged circulation in suspected micro dogleg section to prevent hole wash out and forming ledges
With mobile salts consider using a slightly under saturated mud system to allow a controlled washout. If necessary, increase the
mud weight to help slow down salt intrusion
Consider drilling mobile salts with eccentric PDC bits. Plan regular wiper trips to keep the hole section open
Use hard faced stabilizers and select bits with extra gauge protection if abrasive formations are drilled
Gauge the old bit and stabilizers as well as the bit and stabilizers picked up
Begin reaming 1 joint above a cored hole section. As standard practice, ream the last stand or 3 joints back to bottom on all trip
Page 53
STUCK PIPE
WELLBORE GEOMETRY HOLE PROBLEMS
The indications of Wellbore Geometry problems are observed only when BHA is movin in the hole section with the
geometry problem.
DRILLER INDICATIONS OF WELLBORE GEOMETRY PROBLEMS
TRENDS DRAG TORQUE PRESSURE OTHER
Increasing, erratic Increasing, No change Momentary over pull &
DRILLING erratic set down
Increasing, erratic Surge to start Momentary over pull &
CONNECTION set down
circulation
PREVENTIVE ACTION
Optimize BHA design (run only what is required) and when possible, minimize BHA stiffness
Plan a reaming trip if the new BHA is locked up and/or a hole geometry problem is suspected
Slow down trip speed before BHA enters kick off or doglegs depth, depth of micro dogleg and/or ledges, mobile formation depth
o
Minimize dogleg severity to 3 /100' or less. Minimize rotating hours below a sharp dogleg without a wiper or reaming trip
Consider using key seat wipers or drill string reamers if a key seat is suspected
Limit the length of casing rathole to avoid key seating the bottom of the casing. Do not start angle building operations too close to
the shoe
Avoid prolonged circulation in suspected micro dogleg section to prevent hole wash out and forming ledges
With mobile salts consider using a slightly under saturated mud system to allow a controlled washout. If necessary, increase the
mud weight to help slow down salt intrusion
Consider drilling mobile salts with eccentric PDC bits. Plan regular wiper trips to keep the hole section open
Use hard faced stabilizers and select bits with extra gauge protection if abrasive formations are drilled
Gauge the old bit and stabilizers as well as the bit and stabilizers picked up
Begin reaming 1 joint above a cored hole section. As standard practice, ream the last stand or 3 joints back to bottom on all trip
Page 53
LOST CIRCULATION
HOLE PROBLEMS
LOST CIRCULATION Measurable loss of whole mud (liquid phase and solid phase) to the formation.
Lost circulation can occur at any depth during any operation
NATURALLY EXISTING
Over balanced wellbore pressure is exposed to a formation with unsealed
FRACTURES / HIGH fractures or high permeability
PERMEABILITY
Shut-in pressure
Page 55
HOLE PROBLEMS
LOST CIRCULATION
MECHANISMS
CAUSE:
.
WELLBORE PRESSURE GREATER THAN
FORMATION FRACTURE PRESSURE
.
THE FORMATION FRACTURES ALLOWING
MUD LOSS
WARNING:
.
PROGNOSED LOSS ZONE
.
EXCESSIVE MUD WEIGHT
.
LOW FRACTURE STRENGTH
.
POOR HOLE CLEANING
.
WELLBORE PRESSURE SURGES
CASING INDICATIONS:
SHOE .
MAY BEGIN WITH SEEPAGE LOSS,
POSSIBLE TOTAL LOSS
.
PIT VOLUME LOSS
.
EXCESSIVE HOLE FILL-UP
.
FIRST IF SHUT-IN, SUDDEN LOSS OF PRESSURE
INTERFACE
FIRST ACTION (TOTAL LOSS):
.
REDUCE PUMP SPEED TO 1/2
.
PULL OFF BOTTOM, STOP PUMPS
.
ZERO STROKE COUNTER, FILL ANNULUS
WITH WATER OR LIGHT MUD
.
RECORD STROKES IF / WHEN THE
ANNULUS FILLS UP
.
MONITOR WELL FOR FLOW
PREVENTIVE ACTION:
.
MINIMIZE MUD WEIGHT/MAXIMIZE SOLIDS
REMOVAL
.
LOW PRESS CONTROL PENETRATION RATE
.
SAND MINIMIZE WELLBORE PRESSURE SURGES
.
AVOID IMPOSED / TRAPPED PRESSURE
Page 56
MECHANISMS
LOST CIRCULATION
HOLE PROBLEMS
CAUSE:
UNCONSOLIDATED .
WELLBORE PRESSURE IS OVER BALANCED
TO FORMATION PRESSURE
.
MUD IS LOST TO NATURAL FRACTURES
AND/OR HIGH PERMEABILITY
.
WARNING:
.
PROGNOSED LOSS ZONE
.
LOST CIRCULATION CAN OCCUR AT ANY
TIME DURING ANY OPEN HOLE OPERATION
VUGULAR .
INDICATIONS:
.
MAY BEGIN WITH SEEPAGE LOSS, TOTAL
LOSS POSSIBLE
.
STATIC LOSSES DURING CONNECTIONS /
SURVEY
.
PIT VOLUME LOSS
CAVERNOUS
FIRST ACTION (TOTAL LOSS):
.
REDUCE PUMP SPEED TO 1/2
.
PULL DRILL STRING OFF BOTTOM, STOP
CIRCULATION
.
ZERO STROKE COUNTER, FILL ANNULUS
WITH WATER OR LIGHT MUD
UN .
SE RECORD STROKES IF / WHEN THE ANNULUS
AL
ED FILLS UP
FA .
ULT MONITOR WELL FOR FLOW
.
PREVENTIVE ACTION:
.
MINIMIZE MUD WEIGHT
.
CONTROL PENETRATION RATE
.
FRACTURED MINIMIZE WELLBORE PRESSURE SURGES
FORMATION .
PRE-TREAT WITH LCM
Page 57
HOLE PROBLEMS
LOST CIRCULATION
MECHANISMS
Successful treatment of lost circulation depends greatly on locating the depth of the loss zone
PRESSURE TRANSDUCER
Page 58
RESTORING CIRCULATION
LOST CIRCULATION
HOLE PROBLEMS
SOLUTION GUIDELINES
GUIDELINES FOR LOST CIRCULATION SOLUTIONS
ACTION RESULTS CONSIDERATIONS
Reduced wellbore pressure (the More successful with pressure
MINIMIZE driving force pushing mud into induced fractures
MUD WT the loss zone .
Possible well control event or hole
instability problems
Reactive clays of loss zone swell with More successful with fresh water mud
water of WBM producing a plugging effect lost to shale formations
FORMATION . .
"HEALING Soft shales deform with formation stress Better results with LCM
TIME" helping to "heal" the fracture .
Normal 6 - 8 hours wait time with string
in casing
Effectively bridges, mats and seals Less effective with large fractures,
LOSS CIRC small to medium fractures / faults
MATERIAL permeability .
(LCM) Ineffective with cavernous zones
.
Increase LCM lbs/bbl with loss
severity
A plug base is pumped into the loss zone Can be used in production zones
SPECIALTY followed by a chemical activator .
TECHNIQUES The two materials form a soft plug Increased risk of plugging equipment
.
Plug breaks down with time
Cement slurry is squeezed into the loss Provides a "fit-to-form" solid plug at
zone under injection pressure or near the stress of the surrounding
CEMENT formation
.
The slurry cures to a solid plug .
In some cases, the only practical solution Not a consideration where well control
DRILLING is to drill without returns potential exist
BLIND .
Set casing in the first compentent
formation
requirements. Consult the LCM product guide prior to applying the pill
.
Use large nozzle sizes if the loss potential is high. Keep the string moving during pill spotting operation to avoid stuck pipe
Page 59
LOST CIRCULATION RESTORING
HOLE PROBLEMS CIRCULATION
.COARSE (C) All material will screen-out at shaker. Will plug jets and down hole tools.
Recommended with open-ended pipe
FIBROUS
.Non-rigid materials that form a mat on the hole wall to provide a foundation for normal filter cake
&
development
FLAKED
GRANULAR Rigid materials that bridge and plug the permeability of the loss zone
LCM BLEND A combination of fibrous, flaked and granular materials in one sack
.
CELLULOSTIC Sized wood derived materials used to prevent seepage /partial loss
.
CALCIUM
CARBONATE Sized limestone or marble (acid soluble) used for seepage /partial loss in production zone
Granulated salt (water soluble) developed for seepage /partial loss in production zone in salt-
SIZED SALT
saturated systems
THE LCM MIXTURES SHOWN HERE ARE INTENDED AS A GUIDE WHERE NO FIELD EXPERIENCE EXIST.
SOME SITUATIONS MAY REQUIRE 2 - 6 PPB LCM CONCENTRATION IN THE TOTAL MUD SYSTEM.
CONSULT YOUR MUD COMPANY FOR AVAILABLE PRODUCTS AND PILL FORMULATIONS BEST SUITED
FOR THE AREA.
Page 60
RESTORING CIRCULATION
LOST CIRCULATION
HOLE PROBLEMS
THE LCM MIXTURES SHOWN HERE ARE INTENDED AS A GUIDE WHERE NO FIELD EXPERIENCE EXIST.
SOME SITUATIONS MAY REQUIRE 2 - 6 PPB LCM CONCENTRATION IN THE TOTAL MUD SYSTEM.
CONSULT YOUR MUD COMPANY FOR AVAILABLE PRODUCTS AND PILL FORMULATIONS BEST SUITED
FOR THE AREA.
Page 61
HOLE PROBLEMS
LOST CIRCULATION
.
Shredded Fibrous 1/4" fibers 8
Wood
Page 62
RESTORING CIRCULATION
LOST CIRCULATION
HOLE PROBLEMS
If possible, drill through the loss interval. Pull out of the hole and return open-ended
.
Position the string +/-100 feet above the loss zone
.
Mix 100 sx of cement and 100 sx of bentonite with 50 barrels of diesel (slurry wt - 11.5 ppg, yield - 1.39 cubic feet per sack )
.
Pump down the drill string, 15 barrels of water-free diesel ahead and behind the gunk slurry
.
When the lead diesel spacer reaches the bit, close the BOP and pump mud down the annulus
.
Pump 4 bbls/min down the string and 2 bbls/min down the annulus until the tail diesel spacer clears the string
.
Reciprocate the string slowly, do not reverse circulate
.
Pull the drill string clear of the squeeze. Mix and place the squeeze with a cementing unit, if possible
.
Wait 8+ hours for the gunk to cure, repeat procedure if returns are not regained
.
It may be necessary to drill out the gunk before repeating the procedure
Page 63
HOLE PROBLEMS
LOST CIRCULATION
PREVENTION
Pull out of the hole and return with open-ended drill pipe
Position the open-ended drill pipe approximately 100 feet above the loss zone
Follow the slurry with a sufficient volume of mud or water to balance the U-Tube
It may be necessary to drill out the cement before repeating the procedure
Design the casing program to case-off low pressure or suspected lot circulation zones
Maintain mud weight to the minimum required to control known formation pressures. High mud weight is one of the major
causes of lost circulation
Pre-treat the mud system with LCM when drilling through known lost circulation intervals
Maintain low mud rheology values that are still sufficient to clean the hole
Rotating the drill string when starting circulation helps to break the gels and minimize pump pressure surges
Use minimum GPM flow rate to clean the hole when drilling known lost circulation zone
Control drill known lost circulation zone to avoid loading the annulus with cuttings
Consider using jet sizes or TFA that will allow the use of LCM pills (12/32" jets +)
Be prepared for plugging pump suctions, pump discharge screen, drill string screens, etc.
Page 64
LOST CIRCULATION
HOLE PROBLEMS
DRILLING BLIND
PRECAUTIONS WHILE DRILLING WITHOUT RETURNS
Circumstances may dictate drilling blind until 50 feet of the next competent formation is drilled. Casing is set to solve the lost
circulation problem. A blind drilling operation must have Drilling Manager approval
Use one pump to drill and the other pump to continuously add water to the annulus
Closely monitor torque and drag to determine when to pump viscous sweeps
Pick up off bottom every 15 feet (3m) drilled to ensure the hole is not packing off
Stop drilling and consider pulling to the shoe if pump repairs are required
Consider spotting a viscous pill above the BHA prior to each connection
If circulation returns, stop drilling, raise the drill string to the shut-in position. Stop the pumps and check the well for flow
Pressure Observed - Slowly circulate the kick with the CIrculation Method and present mud weight. Be prepared for an
underground blowout condition
Page 65
RIG REPAIR
UNSCHEDULED An interruption in planned operations caused by a breakdown in the drilling rig equipment. Running
RIG REPAIR rig equipment to failure is not cost effective for the Contractor, Operator or wellbore
PREVENTIVE A program designed to schedule regular inspection, maintenance and/or repair of drilling equipment
MAINTENANCE prior to failure
PROGRAM
(PMP) The historical life expectancy of rig equipment is based on the frequency of maintenance
Page 66
RIG REPAIR
Reduce risk of stuck pipe, well control problems, other unscheduled events
Component failure frequency records defines rig and shore base spare parts inventory
.
Increase operator awareness of the contractor's operational needs
Page 67
INTEGRATED PREVENTATIVE MAINTENANCE PROGRAM (IPMP)
Page 68
IPMP
RIG REPAIR
RIG
IPMP 1-2-4-5-6-10-12-29 15 35 16 19-29-38 36 32
Casing - Depth
12-1/4" HOLE 9-5/8" CSG
30" 1284' Run Csg
INTEGRATE RIG MAINTENANCE WITH THE WELL PLAN
WOC
20" 2800' 8-1/2" HOLE 7" Liner
Run Csg
13-3/8" 5080' WOC
9-5/8" 12,250'
Schedule rig maintenance during low risk operations. This may require early maintenance or risking postponed
7" 14,540'
RIG REPAIR
TOTAL RIG POWER Loss of station keeping Rig drift-off damage Start emergency generator
.
Loss of hoisting, Stuck pipe Initiate preliminary disconnect procedure
rotation, circulation .
Well control Raise drill string off bottom with motion
compensator
Surface equipment
failure / damage Circulate with cementing pump
TOP DRIVE SYSTEM Possible loss of Stuck pipe If possible, trip to casing shoe for repair
(TDS) rotation, hoisting,
circulation Well control If not possible, set slips, tie slip handles and
rotate pipe in slips
HOISTING SYSTEM Cannot raise the Stuck pipe Continue circulation / rotation
drill string
Reciprocate drill string with motion
compensator
ROTATING SYSTEM Cannot rotate the Stuck pipe Reciprocate drill string
drill string
Trip to casing shoe for repair
CIRCULATING Cannot circulate the Stuck pipe Trip to casing shoe for repair
SYSTEM wellbore
Well control Rotate / reciprocate the drill string if repair is
made while in open hole
WELL CONTROL Cannot shut-in during Personnel injury Non emergency - secure the well to make
SYSTEM kick repairs
Equipment damage
Blowout Emergency - Initiate evacuation procedures
Loss of well
Environmental damage
Page 69
DOWN HOLE EQUIPMENT FAILURE
DOWN HOLE An interruption in planned operations caused by drilling /evaluation tool failures other than drill string
EQUIPMENT failures. Down hole tool selection and operation is critical in the reduction of tool failure
FAILURE
PACKER / DST TOOLS Leaks, packer does not release, incompatible with other tools, high angle
holes
Page 70
DOWN HOLE EQUIPMENT FAILURE
Selecting the right tool for the job can significantly reduce tool failure. Following a standardized tool selection procedure ensures
the right tool is selected
DIMENSIONS
TOOL PHYSICAL
PROPERTIES
Length, OD, ID of tool
Weight and grade
Connection type
Special make up torque requirements, thread dope
Stress relief features
OPERATING PARAMETERS
OPERATIONS
Minimum / maximum flow rate
Minimum / maximum operating pressure
Torque / tension limitations
Recommended operating hours
Is a tool operator needed / provided
Special handling tools required
Are special operating instructions required/provided
Operating manual provided
Safety recommendations
Settings / calibration data
Maintenance requirements
Page 71
DOWN HOLE EQUIPMENT FAILURE
Following a standardized check list when the tool arrives insures the right tool has been shipped and was not damaged in transit
inspection report
Locate the operating manual, special instructions (if any), settings and calibration sheet, tool
PHYSICAL
CONDITION Missing or damaged parts and spare parts
COMPATIBILITY
Connection stress relief features match features of the drill string
OPERATION Function test values, flappers, etc. before running tool in hole
AWARENESS / Pre-tour safety meetings with written Tour Operations Plan, Driller Hand Over Notes with
REFRESHERS current/next operations section. Discuss operation of unfamiliar / new technology tools
TOOL FAILURE When tool failure occurs, file a Tool Failure Report to share knowledge of the failure and
REPORT preventive action taken. A statistical data base can be built with this information
SERVICE / Inferior service and tools provided by supply companies can account for a substantial number of
EQUIPMENT tool failures, Included in the Tool Failure Report, is a section on supply company performance
ratings, An alternative supplier should be considered if ratings indicate high tool failure rate
Page 72
DRILL STRING FAILURE PLANNING
MINIMUM YIELD The minimum load (lbs/sq in of metal) at which plastic deformation of the metal begins
STRENGTH (MYS)
METAL FATIGUE Accumulated metal damage caused by stress reversals
Fatigue damage is a naturally occurring process that begins when the component is put into service and accumulates with use.
Stress cracks form and continue to grow which eventually results in string failure if not detected by inspection
Examine the drill string components to ensure it meets minimum Onsite visual inspection, Electronic
INSPECTION inspection based on drill string and drilling
specifications. Inspections detect wear before it results in a
down hole failure conditions
OPERATIONS Improper use, handling and storage of the drill string results in Correct connection make-up Calibrating
premature string failure gauges, Operational use and handling
practices
SURROUNDINGS The chemical and mechanical environment in which the drill Doglegs, Buckling, Vibrations, Corrosion,
string is operated. If the surroundings become hostile, the High angle wells
inspection frequency should be increased to minimize failures
The steps taken to prevent drill string failures is the sum of efforts in these five components. In some cases, efforts in one
component area must be varied to minimize problems in another area
Welding Failure
Page 73
DRILL PIPE FATIGUE
DRILL STRING FAILURE
SLIP AREA 16" to 24" from box end Using one tong, stopping the string with the slips,
worn slips and bowl
TUBE MIDDLE Middle section between pin and Contact with abrasive formation while rotating causing
box OD wear
First 5 stands above BHA Stiffness change from BHA to drill pipe, possibility of
TRANSITION ZONE compressional loading with excessive WOB
PREVENTIVE ACTION
Maintain hole angle changes under 3 /100'
Maintain sufficient levels of corrosion inhibitors and oxygen scavengers
Stop pipe, set slips and lower pipe slowly onto slips to prevent slip cuts
Allow no more than 3' of pipe length above the slips if possible
Always use 2 tongs to make-up and break-out connection
Ensure tongs are at 90 angle in two planes when torquing up connections
Do not run bent pipe, pipe with deep slip cuts or corrosion pits
Go slow when backreaming, minimize the overpull
Always use transition pipe (HWDP) between the drill collars and drill pipe
Move the bottom stand of drill pipe (HDWP) to the top of the drill string on each trip
Rotate the connection breaks on each trip
Use adequate BHA weight to provide bit weight
Check slip insert bowl, master bushing and rotary table for wear
Clean and inspect slip and tong dies frequently
Page 74
DRILL STRING FAILURE DRILL PIPE FATIGUE
90
LOAD LOAD
CELL CELL
90
Page 75
DRILL PIPE FATIGUE DRILL STRING FAILURE
15.50 TW 2
WEIGHT
CODE
4" 14.00 STD 2
.
2
15.75 TW 3
G
MILLED
5" 19.50 STD 2
.
SLOT
25.60 TW 3
G E - E75
X - X95
INTERNAL G - G105
UPSET
S - S135
Page 76
DRILL STRING FAILURE BHA FATIGUE
PREVENTIVE ACTION
Apply recommended make-up torque with tongs at 90 angle in two planes and calibrate tong gauges frequently
Maintain bending strength ratio (BSR) near value recommended for drill collar size
Page 77
BHA FATIGUE DRILL STRING FAILURE
NO
UNENGAGED UNENGAGED
THREADS THREADS
NO BOREBACK
BOREBACK BOX
T e ratio of bo stiffness to pin stiffness . After applying proper torque, bending strength of connection is balanced when
the box stiffness is 2.5 times the pin stiffness
A BSR of 2.5 represents a balanced connection for the average size collar and connection type. As collar OD decreases,
BSR should be reduced to compensate for a weaker box. As collar OD increases, BSR should be increased to compensate
for a weaker pin
BALANCED
CONNECTION
FATIGUE LIFE (CYCLES)
MAXIMUM
LIFE
STRONG STRONG
PIN BOX
Page 78
DRILL STRING FAILURE CARE/HANDLING
DEVELOP A REGULAR HABIT OF DOING 5-SECOND CHECKS. THESE CHECKS CAN BE MADE ON THE PIPE RACK,
V-DOOR, RIG FLOOR, WHILE DRILLING/TRIPPING, AND LAYING DOWN THE DRILL STRING. MARK AND SET ASIDE BAD
JOINTS
Caliper for minimum required OD. Inspect for cracks, eccentric wear (out-of-roundness), severe tong cuts or unusual damage
TUBE INSPECTION
Visually inspect the slip area for deep slip cuts, severe pitting, bent joint
Visually inspect the pipe bore for debris, scale. Rabbit all drill pipe before use
Caliper the middle of the tube for minimum required OD and eccentric wear (out-of-roundness)
Use a soft bristle brush and solvent to clean the threads and shoulder for a visual inspection
Inspect for eccentric wear (out-of-roundness), severe tong cuts or unusual damage
Visually inspect the sealing shoulder and threads for impact damage, pitting, galled surfaces, correct connection type, stretched pin
Look for abnormal connection ID's that are not consistent with the string
Page 79
CARE/HANDLING DRILL STRING FAILURE
DRILLING TRIPPING
Keep the mousehole and rathole clean Alternate and record the break on each trip
Visually inspect kelly saver sub at frequent intervals Do not let the slips ride the drill sting
Clean and inspect tong and slip dies at frequent intervals Stop the pipe, set slips, slowly set pipe weight on slips to
minimize slip cut depth
Keep handling subs clean and free of damage
Allow no more than 3 feet pipe length above slips
Allow no more than 3 feet of pipe above slips when
Always use 2 tongs to make-up and break-out connections.
making/breaking
Use a pipe spinner to spin-up and back-out connections
Use correct dope compound for the specific connection. Never apply the tongs on the drill pipe tube
Dope threads and shoulder generously
If a connection requires excessive break-out torque or the
Do not roll the pin into the box, pick up and re-stab connection has dry or muddy threads on break-out:, clean
and visually inspect the pin and box for damage
Always use 2 tongs to make-up and break-out connections
Watch for these signs on trips:
Use a pipe spinner to spin-up and back-out connections
Shoulder damage Worn or missing bevels
Belled box Galled or burned threads
Use proper make-up torque for the specific connection
Stretched pin Eccentric box/tube wear
o
Torque connections with tongs at 90 angle in two planes Keep pipe set back area clean. Rinse mud off outside and
inside of pipe. Install pipe wiper as soon as possible
Correct recommended make up torque (RMUT) for dope
friction factor Do not use a hammer or pipe wrench to move stands on the
pipe rack, use a pipe jack
RMUT o = RMUT x Dope Friction Factor
Do not roll the pin into the box, pick up and re-stab the
Use a steady pull to torque-up the connection connection
Page 80
DRILLING JARS
DRILLING JAR A drilling tool designed to deliver high impact "hammer" blows to the stuck drill string
ADVANTAGE Higher probability of recovery with immediate and correct application of jar blows
OUTER CLOSED
BARREL
SPLINE
DRIVE
LATCH
MECHANISM
LOWER
SEAL
WASH
PIPE
Hyd. Oil
Flowing Trapped
By Piston Oil Stops
Upward Oil
Movement Flowing
of Mandrel By Piston
Metered
Flow
Delays
Latch
Trip
Page 81
DRILLING JARS
LOWER
SEAL
2000 PSI
BOTTOM AREA
OF WASHPIPE,
10 SQ INCHES
See jar manual for POF information for your jar make, model and size
Page 82
DRILLING JARS
Slow down or stop the pumps or bleed trapped pressure to After cocking the jar, pump pressure can be increased to reduce
reduce the slack-off weight required to trip the jar pick-up weight required to trip the jar
HYDRAULIC JAR
Slow down or stop the pumps or bleed trapped pressure to After cocking the jar, pump pressure can be increased to reduce
reduce the slack-off weight required to trip the jar pick-up weight required to trip the jar
No delay time is required, the latch will trip when the preset No delay time is required, the latch will trip when the
trip-load is applied to the jar present trip-load is applied to the jar
If the jar does not trip, slow down or stop the pumps or bleed If the jar still does not trip, increase circulating pressure to
trapped pump pressure to reduce pump open force maximum to increase the pump open force. Do not apply
trapped pressure, however
If the jar still does not trip, slack off additional weight
(10,000 to 20, 000 lbs) If the jar does not trip, pick up additional weight
(10,000 to 20,000 lbs)
Page 83
DRILLING JARS
TRIPPING THE JAR
HYDRAULIC JAR
DOWN-JAR BLOW UP-JAR BLOW
After cocking the jar, slack-off to the calculated weight After cocking the jar, pick-up to the calculated weight indicator
indicator load load
Lock down the brake and wair for the jar time to elapse. See Lock down the brake and wait for the jar time delay to elapse.
your jar manual (30-60 sec short cycle, 2-8 min long cycle) See your jar manual (30 - 60 sec short cycle, 2-8 min long
cycle)
If the jar does not trip, stop pumping or bleed trapped
pressure. Recock the jar and apply trip load If the jar does not trip, circulate at max rate and allow
additional time (do not apply trapped pressure)
If the jar still does not trip, slack-off more weight and allow
more time If the jar still does not trip, stop pumping and recock the jar
and apply trip load
DOWN-JAR OPERATING SEQUENCE (MECH OR HYD) UP-JAR OPERATING SEQUENCE (MECH OR HYD)
FROM CLOSED FROM OPEN
POSITION: POSITION: (3)
(3) DRILL
(1) WEIGHT IS STRING
SLACKED STRETCHES
DRILL (1) AS TENSION
STRING OFF WEIGHT IS IS APPLIED (5)
IS RAISED (5) SLACKED DRILLSTRING
OFF
BHA MASS IS CONTRACTS
HW ACCELERATED
DP BY HW
GRAVITY DP (6)
BHA MASS IS
ACCELERATED
DC
DC
DC
8" DC
8"
(4)
JAR
(2) LATCH
JAR TRIPS
COCKS (2)
JAR (4)
(6) COCKS JAR
IMPACT IS LATCH
TRIPS
DELIVERED
(7)
IMPACT IS
STUCK DELIVERED
PIPE
STUCK
PIPE
Page 84
DRILLING JARS
JAR OPERATIONS
REASONS FOR JAR NOT TRIPPING
MECHANICAL JAR HYDRAULIC JAR
Jar not cocked Jar not cocked
. .
Stuck above jar Not waiting long enough
. .
Jar failure Stuck above jar
. .
Pump open force not considered Jar failure
. .
Pick-up /slack-off weight incorrect Pump open force not considered
. .
Unknown /incorrect trip load setting Pick-up /slack-off weight incorrect
. .
Excessive hole drag Excessive hole drag
. .
Right-hand torque trapped in torque sensitive jar
JAR HANDLING
JAR HANDLING RECOMMENDATIONS
If a service connection is found loose, call the shop for recommended torque. Do not use tooljoint torque on these connections
.
Do not tie the chain hoist, apply the tongs or set the slips on the exposed polished section of the inner mandrel
.
A mechanical jar is shipped in the cocked position. Run the jar in the extended or cocked position
.
Rack a mechanical jar in the derrick in the cocked position at any position in the stand
.
A hydraulic jar is shipped with a safety clamp on the inner mandrel. The jar must be run in the open position
.
Rack a hydraulic jar in the derrick with the safety clamp at any position in the stand
DRILLING ACCELERATOR
An energy storing device designed to optimize the drilling jar assembly for maximum up and down jar-blow intensity
ADVANTAGES Protects the drill string and rig surface equipment from
high impact loads
Page 85
DRILLING JARS
DRILLING ACCELERATOR
OVERPULL!!
INNER
MANDREL
OUTER
BARREL
SPLINE
DRIVE
NITORGEN EXPANDS
NITORGEN EXPANDS
NITORGEN
COMPRESSED
NITROGEN BY APPLIED
(2000 psi) OVERPULL
LOWER
SEAL
WASH
PIPE
BHA MASS
ACCELERATED
HW
DP
4
ACCELERATOR 6
STROKES OUT BHA
ACCELERATED
ACC
5
2 JAR LATCH
JAR TRIPS
COCKS DC
Page 86
DRILLING JARS
In 70% of sticking occurrences, down jarring is required. Jar /accelerator placement programs are available through jar
service companies
DP DP
HW HW
DP DP
WEIGHT FOR WEIGHT
UP AND DOWN FOR DOWN
JAR BLOW JAR BLOW
EQUAL TO 1.2+ OF
DOWN-TRIP DOWN-TRIP
LOAD
LOAD
ACCEL
WEIGHT
FOR UP
JAR BLOW
JAR
0.2 OF UP-
DC
TRIP LOAD
DC
DC
JAR
DC
DC
Page 87
DRILLING JARS
Match the jar and accelerator OD of the OD to the BHA section the component will be placed in (i.e., use 8" jar in 8" collar
section, 6-1/2" accelerator in the HWDP section). Use the largest jar size (OD) for the hole size
Place the jar and accelerator 5000 lbs of BHA weight above or below the neutral zone to avoid pre-mature wear
If the drilling jar assembly is not equipped with an accelerator, optimize the jar position for a 70% probability of down jarring
Visually inspect jars each trip for any indication of damage, loose connections, excessive wear or leakage
Caution should be exercised not to run the jar directly between drill collars and heavy weight drill pipe, directly between
stabilizers or collar strings of different OD size.
Do not run hydraulic drilling jars in close proximity to other hydraulic drilling jars.
Do not run a stabilizer or key seat wiper above the jar to avoid getting stuck above the jar
If the jar is run in compression, place the jar where the BHA weight above the jar (required for bit weight) does not exceed
pump open force at normal circulating pressure. The jar will remain in the open position (if circulation is maintained) even
with full bit weight applied
If the jar is run in compression, consider using a jar model that is internally counter balanced. The increased pump open force
will hold the jar in the open position while drilling
Consult the jar service company for detailed jar/accelerator placement advice
Page 88
DRILLING JAR / ACCELERATOR PLACEMENT WORKSHEET (0 - 60 )
JAR/ACC ASSEMBLY HOLE SIZE: RECOMMENDATIONS BHA : JAR ASSEMBLY
DP DP
Wt Factor
STANDS
ABOVE JAR:
DOWN-
JAR
STANDS:
TOP
HWDP ACCELERATOR
BTM
Page 89
JAR BUOYANCY FACTORS (BF) HOLE ANGLE FACTORS (AF)
STANDS: 9.0 10.011.0 12.013.014.015.016.017.018.019.0 20.0 9 < 10 15 20 25 30 35 40 45 50 55 60
DRILLING JARS
.86 .85 .83 .82 .80 .79 .77 .76 .74 .73 .71 .69 1.0 .99 .97 .94 .91 .87 .82 .77 .71 .64 .57 .5
WOB:
WOB:
DRILLING JAR / ACCELERATOR PLACEMENT WORKSHEET (> 60 )
JAR/ACC ASSEMBLY Hole si e: RECOMMENDATIONS BHA :
1.
2.
3.
DP
BUOYANCY FACTORS (BF) HOLE ANGLE FACTORS (AF)
9.0 10.011.0 12.0 13.014.0 15.016.0 17.018.0 19.0 20.0 9 < 10 15 20 25 30 35 40 45 50 55 60
.86 .85 .83 .82 .80 .79 .77 .76 .74 .73 .71 .69 1.0 .99 .97 .94 .91 .87 .82 .77 .71 .64 .57 .5
5.
DOWN-
Page 90
JAR
STANDS:
DRILLING JARS
HWDP
DOUBLE-ACTING STEERABL
E A SSEMB
ACCELERATOR LY
JAR
HWDP
WELL CONTROL
WELL PRESSURE The control of formation fluid flow (kick) into the wellbore
CONTROL
SECONDARY Control of kicks with HSP assisted by Safety kill the kick without the
(Second Line Of Defense) blowout preventer equipment loss of circulation
TERTIARY Avoid a surface blowout. Regain
An underground blowout
.
PRIMARY
THE PRIMARY CONTROL TOOL
HYDROSTATIC PRESSURE The pressure developed by the height and density of a non-moving
(HSP) fluid column
PPG = LBS PER GALLON FLUID DENSITY
.
0.052 = PPG TO PSI/FT CONVERSION FACTOR
.
TVD = TRUE VERTICAL DEPTH (FT)
To prevent formation fluid flow into the wellbore (kick), hydrostatic pressure must be at least equal to the highest pressured
permeable zone of the open hole.
SAND
HSP
FORMATION PRESSURE 4700 psi
5200 PSI
Page 91
PRIMARY
WELL CONTROL
The piston affe t of upward string Maximum swab pressure occurs at the bit and is equally
movement causing a de rease in imposed to the bottom of the wellbore
SWAB well-bore pressure which can .
induce a kick As string motion is started, additional surge pressure is
imposed to break the gel strength of the mud and accelerate
the mud column
The piston affe t of downward string Maximum surge pressure occurs at the bit and is equally
movement causing an in rease in well- imposed to the bottom of the wellbore
SURGE bore pressure .
As string motion is started, additional surge pressure is
required to break the gel strength & accelerate the mud
column
PUMP The pump pressure required to break Pump surge pressure to break circulation can be (in some
SURGE the gel strength of the mud and cases) greater than the normal circulating pressure
accelerate the mud column
6500
LOSS OF CIRCULATION / UNDER GROUND BLOWOUT
FRACTURE PRESSURE = 6200 psi
ACCELERATE
DECELERATE
START PUMPS
6000
STEADY SPEED STATIC STEADY CIRCULATION
DECELERATE
ACCELERATE
TIME
Page 92
WELL CONTROL PRIMARY
0'
Ann Fric psi
ECDppg = ( TVD Ft X .052)+ MW ppg
2500'
AN
NU
=
( 10,000 X .052 ) + 10.0
400
TVD
=
LU
5000'
FR
IC
TI
ON
PR
ES
SU
7500'
RE
=
HYDROSTATIC
40
PRESSURE
0P
5200 PSI
SI
10,000'
0 1 2 3 4 5 6 7
PRESSURE (1000 psi)
ADVANTAGE DISADVANTAGE
Built-in safety factor during a kick killing operation Penetration rate decreases as ECD increases
. .
Safety factor if circulating near or slightly under balance to Increases potential for lost circulation, differential sticking,
formation pressure wellbore instability
KICK TOLERANCE
The maximum under balance kick load (ppg), considering an estimated kick volume, the casing shoe can tolerate without fracturing
Page 93
PRIMARY
DRILLING JARS
Monitor the well for signs of changing formation pressure Driller Geologist
. Mud logger Drilling Engineer
Shaker man Company Rep
.
Company Rep Geologist
Ensure mud weight is correct before drilling into known Mud Logger Drilling Engineer
high or low pressure zones Toolpusher
.
Driller
Ensure a means of disposing of contaminated fluid to Mud Engineer Toolpusher
avoid contaminating the mud system Shaker Man Company rep
. Derrick Man
Ensure proper mud weight is used to fill the hole on trips Shaker Man Driller
. Derrick Man Mud Engineer
Maintain pit valve seals to avoid accidental dilution
Maintain mud box seals, ensure drain is plumbed to the trip A/D Compant Rep
tank or annulus if filling with pump strokes Floor men Toolpusher
.
. .
A/D Company Rep
Maintain hole full during non-criculating operations Driller Toolpusher
Page 94
WELL CONTROL SECONDARY
SECONDARY The control of formation fluid flow by the use of hydrostatic pressure ASSISTED by blowout
WELL CONTROL preventer equipment
KICK TYPES
UNDER BALANCE KICK
Kick caused by an increase in formation pressure above wellbore hydrostatic pressure
WARNING:
.
PROGNOSED ABNORMAL FORMATION
PRESSURE
.
OFFSET WELL DATA
INDICATIONS:
.
GEOLOGIST / MUD LOGGER ABNORMAL
PRESSURE TREND CHANGES
DRILLING BREAK
.
WELL FLOW /PIT GAIN
FIRST ACTION:
.
SOUND KICK ALARM
4700 psi
.
POSITION DRILL STRING FOR SHUT-IN
.
STOP THE PUMPS /SHUT-IN THE WELL
PREVENTIVE ACTION:
.
ADJUST MUD WEIGHT PRIOR TO DRILLING
KNOWN ABNORMAL PRESSURED ZONE
.
Gas Kick OBSERVE ABNORMAL PRESSURE WARNING
SIGNS
300 psi
HSP loss
Sand
5500 psi
Page 95
SECONDARY
WELL CONTROL
KICK TYPES
INDUCED KICK
Kick caused by a decrease in hydrostatic pressure below formation pressure of a premeable zone
MUD)
(SWABBING, LOST CIRCULATION, LIGHT
WARNING:
.
FOR SWABBING
NOTE:
A kick was INDICATIONS:
swabbed in & .
bottom TRIP
FIRST ACTION:
.
.
4700 psi
CIRCULATION
String HSP
PREVENTIVE ACTION:
.
300 psi .
HSP loss .
Sand
4700 psi
Page 96
KICKS
Page 97
/E U S EA
PLAN CHANGE ND Q LB
CO UI EL /W
E P W M
OR PL R
LB AN F O
CO. W
EL TP AT
PL
WELL CONTROL
EVACUATION
WELLBORE OPERATIONAL PLAN, MECHANICAL REQUIREMENTS PERSONNEL READINESS
SUPERVISOR SUPERVISOR
G MECHANICAL LIMITS, RIG / VESSEL CONDITIONS
IN
EER T
N R
GI PPO
EN SU
DRLG. STANDBY
ENG. VESSEL
SECONDARY
SECONDARY
WELL CONTROL DRILLING KICKS
DRILLING BREAK Indicates a new formation exposed to the well. Driller Co Rep
Under balance kicks are usually preceded by an Mud Logger Geologist
abrupt ROP change, increase or decrease Toolpusher
WELL FLOW Kick fluids displace mud from the wellbore Driller Drl Crew
increasing the return flow or causing well flow with Mud Logger Toolpusher
the pumps off Shaker Man Co Rep
Derrick Man Mud Engineer
As kick fluids flow into the wellbore, the volume Driller Drl Crew
PIT VOLUME GAIN addition is detected by the pit volume totalizer (PVT) Mud Logger Toolpusher
Shaker Man Co Rep
Derrick Man Mud Engineer
Page 98
DRILL KICKS
WELL CONTROL SECONDARY
INDICATIONS
INDICATIONS OF INDUCED KICKS
LOSS OF MUD WEIGHT
(LIGHT MUD PUMPED, SWABBED GAS , CORE GAS)
INDICATIONS NOTES RESPONSIBILITY NOTIFY
PUMP PRESSURE Lower density kick fluid decreases annulus hydrostatic Driller Toolpusher
pressure allowing the drill string mud column to U-tube Derrick Man
DECREASE / SPM to the annulus
Mud Logger
INCREASE Mud Eng
Kick fluids displace mud from the wellbore increasing Driller Drl Crew
WELL FLOW return flow or causing well flow with the pumps off Mud Logger Co Rep
Shaker Man Toolpusher
Derrick Man Mud Eng
. .
As kick fluids flow into the wellbore, the volume Driller Drl Crew
PIT VOLUME GAIN addition is detected by the pit volume totalizer (PVT) Co Rep
Mud Logger
Shaker Man Toolpusher
Derrick Man Mud Eng
If flow is detected, initiate shut-in procedure If flow is detected, initiate shut-in procedure
Page 99
SECONDARY
WELL CONTROL DRILLING KICKS
Raise the kelly / top drive to shut-in position Raise the kelly / top drive to shut-in position
. .
Maintain f ll ir lation Maintain f ll ir lation
Open down-wind diverter line and close the diverter Prepare to abandon the location
Open pump suctions to the heavy mud reserves and Monitor the sea surface for gas. Move the rig up-wind of
pump at maximum rate surfacing gas
Building additional heavy mud volume Fill pits with sea water
Prepare to abandon the rig Continue pumping the heaviest fluid available at
maximum rate
.
Gas one depletion ma ta e
several o rs or da s
Raise the kelly / top drive to shut-in position Raise the kelly / top drive to shut-in position
. .
Stop circulation Stop circulation
Open the choke line valve Open the choke line valves
Close the upper pipe rams or annular preventer Close the upper annular preventer
Record SIDPP and SICP every 2 minutes Record SIDPP and SICP every 2 minutes
If necessary, adjust annular preventer operating pressure If necessary, adjust annular preventer operating pressure
relative to stabilized SICP relative to stabilized SICP
Page 100
DRILLING KICKS
WELL CONTROL SECONDARY
A constant bottom hole pressure method to prevent A constant bottom hole pressure method to prevent
additional kicks additional kicks
. .
Minimizes kill pressures imposed to wellbore and Minimizes kill pressures imposed to wellbore and equipment
equipment .
. Kills the kick in one bottoms-up circulation
Kills the kick in one complete circulation
If shut-in pressures are contained without fracture, The depth of the influx at shut-in is seldom known. Actual bit-to-
the probability of a successful kill is greater than 90% shoe strokes cannot be determined. Follow Circulation Method
kill procedure
Page 101
SECONDARY
SHAKER/ FLOOR
DERRICK MEN
MAN
Page 102
ND /E S LB EA
KILL DATA Q W
CO UI EL /
RE P W M
PL R
L BO AN O
CO. EL TF
W LA
KICK CONTROL TEAM
TP P
WELL CONTROL
REP.
OVER-SEE OPERATIONAL PLAN, MECHANICAL REQUIREMENTS
OPERATE EVACUATION
READINESS
OPERATION CHOKE
DRLG. STANDBY
ENG. VESSEL
KICKS
WELL CONTROL
WELL CONTROL SECONDARY
Sub sea stack: remove any gas trapped in the BOP stack
.
Check the well for flow. Condition the mud system
Page 103
SECONDARY
WELL CONTROL KICKS
Close the lower pipe ram to isolate the wellbore from the stack gas clearing operation
Open the kill line failsafe valves. U-tubing pressure from choke line will be observed if choke line fluid density is
greater
Displace the kill line with kill mud weight (KMW) pumping down the choke line and returning through the kill line
- hold kill line pressure constant and increase pump to kill pump rate. Record circulating pressure
- hold pump speed constant & adjust choke to hold circulating pressure constant until KMW returns
Displace only the choke line with water. Allow pump pressure to increase as water is pumped
Open the choke line completely to allow the trapped gas to expand into the choke line
When expanding flow from the choke line stops, open the annular preventer completely to allow the riser to u-
tube into the choke line
When u-tubing flow stops, close the choke line failsafe valves
Close the diverter and open the down-wind overboard line (or flow line degasser)
Open the kill line failsafe valves and displace the riser with KMW. Displace choke line with KMW
Open the lower ram and check the well for flow
Page 104
TRIPPING KICKS
WELL CONTROL SECONDARY
Set the top tooljoint on the slips Set the top tooljoint on the slips
. .
Install and close full open safety valve Install and close the full open safety valve
. .
Observe the well for flow 5 - 10 minutes Line-up the trip tank and observe well for flow
.
5 - 10 minutes
Maintain slow rotation to prevent sticking .
.
Maintain slow rotation to prevent sticking
If flow is detected, initiate shut-in procedure .
Page 105
SECONDARY
WELL CONTROL TRIPPING KICKS
Set the top tooljoint on the slips Set top tooljoint on the slips
Install and close the full open safety valve Install and close the full open safety valve
Open down wind diverter line and close the Make-up top drive /kelly and pump the heaviest
diverter available fluid at maximum rate
.
Set the top tooljoint on the slips Set the top tooljoint on the slips
. .
Install and close the full open safety valve Install and close the full open safety valve
.
Maintain string movement to prevent sticking Maintain string movement to prevent sticking
Page 106
TRIPPING KICKS
WELL CONTROL SECONDARY
HEAVY PIPE The weight of the drill string is greater than the hydraulic force of shut-in
pressure acting to push the string out of the hole
LIGHT PIPE The hydraulic force acting to push the string out of the hole is greater than
string weight (string is supported or pushed out of the hole)
NO PIPE IN HOLE The drill string is pulled out of the hole before the kick is detected
.
IF THE INFLUX DOES IF THE GAS MIGRATES LAST RESORT OPTION
NOT MIGRATE
HEAV MUD CAP TO SURFACE
LUBRICATE BLEED BULLHEAD
.
Page 107
SECONDARY
WELL CONTROL KICKS
Calculate the maximum casing pressure limit (MCPL) to determine when to stop stripping and circulate a portion of the influx out of
the wellbore
MCPL = MASP X .8
.
Calculate displacement volume per stand of pipe stripped into the hole
Adjust the annular preventer closing pressure for stripping. Route the lubricating mud volume to the trip tank
Apply 100 - 200 psi safety factor. Hold the choke closed and strip 1 - 2 stands until safety factor is reached (SICP + SF).
If necessary, bleed SICP to safety factor value
Strip in a stand and alternately bleed out the bbl/std volume. SICP will return to the safety factor value if the bit is above the influx
SICP will increase as the BHA enters the influx and decrease as the BHA moves below the influx
Continue stripping to bottom. Use the Circulation Method with present mud weight to kill the kick
11
10
Overbalance restored
as bit reaches bottom
Casing psi ( 100)
7
Influ disp Bit below Influ pushed up
DC annulus influ hole by pipe disp
6
BHA enters influ
5
Bit on
bottom
4
7 8 9 10 11 12 13 14
Stands Stripped
If maximum casing pressure limit is reached (MCPL), stop stripping operation. Use the Circulation Method with present mud
weight and 100 -200 psi safety factor to circulate a portion of the influx out. Continue stripping to bottom
Page 108
KICKS
WELL CONTROL WELL CONTROL
VOLUMETRIC GUIDELINES
Route returns from the choke manifold to the trip tank
.
Calculate the maximum allowable surface pressure (MASP) to avoid formation fracture
.
MASP = (Frac ppg - Mudppg ) X 0.052 X TVDshoe
.
Calculate the required barrels to bleed (B/BBLs) before allowing casing pressure to increase by 50 psi
.
.
B/BBLs = Bbls/Ft open hole X 50 Mudppg 0.052
Hold the choke closed and allow the migrating gas to increase casing pressure by a 100 - 200 psi safety factor. If accessible,
drill pipe pressure will show an equal increase
.
When calculated casing pressure is reached (SICP + SF), bleed mud through the choke to maintain casing pressure
.
After bleeding the calculated barrels (B/BBLs), hold the choke closed and allow casing pressure to increase by 50 psi
.
When calculated casing pressure is reached (SICP + 50 psi), bleed mud through the choke to maintain the new casing pressure
.
If shut-in off bottom, continue repeating this procedure until shut-in pressures indicate the gas has migrated above the bit
.
Use the Circulation Method with present mud weight and - psi safety factor to circulate the gas out of the hole
.
If shut-in with no pipe in the hole, continue this procedure until the gas migrates to surface
.
Use the Lubricate & Bleed guidelines to remove the gas
11
10
Bleeding B/BBLs
Gas At Bit 50 psi Increase
9
SICP
8
Casing psi ( 100)
6 SIDPP
2
Gas Above Bit
1 Safety Factor
0
7 8 9 10 11 12 13 14
Time (Hrs)
Page 109
SECONDARY
WELL CONTROL KICKS
Construct a schedule for barrels lubricated into the wellbore versus casing pressure decrease. A 50 psi safety factor is
recommended
When preparations are complete, zero the pit level indicator and start the kill operation:
- Adjust the choke to hold casing pressure at it's shut-in value while increasing the pump speed
- Increase pump speed to 1 - 2 barrels per minute. Maintain SPM onstant during the kill procedure
Apply a 50 psi safety factor. Adjust the choke to maintain casing pressure at it's shut-in value until the pit level decreases by the
LUB BBLs
.
Continue holding the pump speed constant and allow the casing pressure to decrease. As the lubricated mud volume increases
hydrostatic pressure, casing pressure will decrease accordingly
8
Total LUB
BBLs
7
6
Casing psi ( 100)
5
Calculated Csg
Pressure
4
1
50 psi Safety Factor
0
0 15 30 45 60 75 90 105 120 135 150 165 180 195
LUB BBLs
When the total barrels are lubricated into the well and casing pressure has decreased to +/-50 psi (safety factor), stop the pump
and allow casing pressure to bleed to zero
Page 110
UGB
WELL CONTROL TERTIARY
TERTIARY Methods employed to contain an under ground blowout and regain primary well control
WELL CONTROL
CAUSE:
.
WELLBORE PRESSURE EXCEEDS FRACTURE
STRENGTH RESULTING IN LOSS OF CIRCULATION
.
KICK FLUID FLOWS UPWARD TO
LOSS ZONE LOSS ZONE
.
WARNING:
.
PROGNOSED LOSS CIRCULATION
.
EXCESSIVE MUD WEIGHT
.
SHALLOW LOW PRESSURE ZONE
.
LOW KICK TOLERANCE
.
INDICATIONS:
.
POSSIBLE WHEN SHUTTING IN FOR A KICK OR
DURING KICK KILLING OPERATION
.
LARGE PIT GIAN
.
SICP STOPS INCREASING AND/OR BEGINS TO
DECREASE
.
PARTIAL /TOTAL LOSS OF RETURNS
.
FIRST ACTION:
.
KILL THE KICK ZONE BEFORE
ATTEMPTING TO TREAT THE LOSS
ZONE
.
PREVENTIVE ACTION:
.
MINIMIZE MUD WEIGHT
.
MAINTAIN SUFFICIENT KICK TOLERANCE
.
MINIMIZE WELLBORE PRESSURE
SURGES
HIGH PRESSURE
KICK ZONE
Page 111
TERTIARY
WELL CONTROL UGB
CAUSE:
.
LOSS OF CIRCULATION OCCURS IN THE LOWER
SECTION OF THE OPEN HOLE
.
REDUCED HYDROSTATIC PRESSURE INDUCES
A KICK
.
FORMATION FLUIDS FLOW DOWN-WARD TO
THE LOSS ZONE
.
WARNING:
.
PROGNOSED LOSS CIRCULATION
.
EXCESSIVE MUD WEIGHT
.
LOW OR SUBNORMAL FORMATION PRESSURE
.
POTENTIAL KICK ZONE ABOVE LOSS ZONE
.
INDICATIONS:
.
POSSIBLE WHEN SHUTTING IN FOR A KICK OR
DURING KILL OPERATION
.
LARGE PIT GAIN
.
PARTIAL OR TOTAL LOSS OF RETURNS
KICK ZONE
.
FIRST ACTION:
.
TREAT THE LOSS ZONE BEFORE ATTEMPTING
TO KILL THE KICK ZONE
.
PREVENTIVE ACTION:
.
MINIMIZE MUD WEIGHT
.
MINIMIZE WELLBORE PRESSURE SURGES
.
CASE-OFF POTENTIAL KICK ZONES BEFORE
DRILLING INTO POTENTIAL LOSS ZONE
LOW PRESSURE
LOSS ZONE
Page 112
UGB
WELL CONTROL TERTIARY
Casing pressure fluctuations during shut-in stabilization Electric wireline surveys can be used to determine if a
period down-flowing UGB is occurring
Shut-in casing pressure continues to increase while shut-in Shut-in pressures are zero initially
drill pipe pressure remains constant
Consult your Mud Engineer for the most applicable "flash setting" lost circulation plug(s)
After pumping the LCM plug in place, start filling the annulus with the present mud weight to control the kick zone
When the annulus fills up, stop the pump and check the well for flow
Use the Circulation Method (Driller's) with present mud weight to kill the kick zone
Page 113
TERTIARY
WELL CONTROL UGB
HEAV PILL
Determine the true vertical measurement between the kick zone and loss zone (TVD K-L )
Calculate the kill mud weight required to kill the kick zone (KMW PPG)
(
KMWPPG = TVD x .052
K-L
) + SAFETY FACTOR
(FPKICK - FPLOSS)
PPG
If KMWPPG equals the density capacity of the weighting material, refer to the Heavy Pill/Gell Pill Guidelines
If KMWPPG is greater than the density capacity of the weighting material, refer to the Barite Plug Guidelines
Build KMWPPG volume equal to 2 to 3 times the open hole volume. If possible, remove the bit jets
Pump sea water at maximum rate, 3 to 4 times the open hole volume ahead of the heavy pill
Pump the heavy pill down the drill string at maximum rate while pumping the gel pill down the annulus to increase injection
pressure at the loss zone
Adjust the annulus pump speed to place the gel pill at the loss zone as the heavy pill reaches the bit. Continue to pump the
heavy pill at maximum rate
BARITE PLUG
A barite plug works best with gas blowouts. High flow rate salt water blowouts wash the barite into the loss zone. Bit plugging
and/or stuck pipe may occur
Consult your Cementing and/or Mud Engineer for detailed recipes and application protection
Page 114
OPERATIONS
WELL CONTROL
SOLUTION GAS Gas that has dissolved into the base oil of oil base mud
BUBBLE POINT
The pressure and temperture condition that will allow the gas to break out of solution
PRESSURE
The sensitivity of the pit volume monitoring system cannot detect vomume changes under +/- 5 barrles. A small kick volume can
enter the wellbore ompletl ndete ted.
Bubble Point
1000' - 2000'
12 bbls
2500' Gas Volume 2500' No E pansion
Depth
Depth
10,000' 10,000'
0 3 bbls Bbls 1400 0 3 bbls
Bbls 1400
Gas expansion allows kick detection well before reaching surface Solution gas does not expand until a near surface bubble point
pressure is reached
Gas solution in OMB does not hinder the detection of large volume kicks (> 5 bbls). Normal kick detection applies. After shutting in
the well, normal i illin pro ed res appl
Page 115
OBM
WELL CONTROL OPERATIONS
Kicks of 5 barrels or less can occur completely undetected under normal operating conditions
INFLUX GUIDELINES
If an influ is suspected, stop the operation and circulate all or part of bottoms up strokes through the choke manifold
Open the choke line valves and open one choke completely
If the position of the gas in the annulus is not known, close the BOP and circulate bottoms up strokes through the choke
manifold
If the position of the gas in the annulus is known, circulate 80% of bottoms up strokes from gas depth, close the BOP and
circulate the remaining strokes through the choke manifold
DRILLING
Drilling operations have the greatest potential of circulating solution gas to surface
Adjust the high /low level mud monitoring alarms as sensitive as possible
Stop drilling for mud wt adjustments, coordinate mud transfers with connections
Use recommended procedures to circulate bottoms up after flow-checking a suspected drilling break and for all unaccountable
pit gains
TRIPPING
Tripping has the least potential of solution gas erupting at surface as solution gas will not migrate. Use recommended procedure
to circulate bottoms up after all short or round trips
Regardless of kelly /top drive position, stop the rotary and pumps, close the annular preventer (Sub sea, close the diverter)
Page 116
WELL CONTROL KILL SHEET
(A) WELL DATA (C) CALCULATIONS (E) DRILLPIPE PRESSURE
SCHEDULE
Kill Mud Weight (KMW) ppg
Original Mud Weight (OMW)
KMW = (SIDPP TVD .052) + Original Mud Weight STROKES PRESSURE
ppg
ICP
KMW = ( .052) +
(1)
True Vertical Depth (TVD)
Initial Circulating Pressure (ICP) psi (2)
ft (3)
ICP = Kill Pump Pressure + SIDPP
(4)
Kill Pump Pressure (KPP) ICP = + (5)
psi Final Circulating Pressure (FCP) (6)
psi
(7)
Kill Pump Rate (KPR) FCP = Kill Pump Pressure x KMW OMW
(8)
spm FCP = x (9)
Stks to FCP
Bit (10)
Strokes to Bit
stks
Page 117
(D) WAIT & WEIGHT PROCEDURE
INSTRUCTIONS:
1. Raise mud weight in pit to Kill Mud Weight value.
WELL CONTROL
.
2. Monitor shut-in pressures for gas migration. If 1. Record ICP, FCP and Stks to Bit in
(B) KICK DATA spaces indicated.
necessary, bleed mud to maintain SIDPP at initial
shut-in value. 2. Calculate strokes increase per Increment.
Shut-In Drillpipe Pressure (SIDPP) . .
3. When kill preparations are complete, refer to Pump Stks to Bit 10 = Stks Inc
psi Start Up procedure and bring the well on choke.
. Add Stks Inc to each increment until Stks
4. Hold kill pump rate (KPR) constant and adjust the to Bit is reached.
Shut-In Casing Pressure (SICP) choke to maintain the Drillpipe Pressure Schedule
3. Calculate drillpipe pressure decrease per
until Kill Mud Weight returns. increment.
psi . .
5. Stop the pump, close the choke and check shut-in (ICP - FCP) 10 = PSI Dec
pressures. Sub Sea Stack - Clear gas from BOP and
kill riser. From ICP, subtract PSI Dec from each
Pit GainOO increment until FCP is reached.
.
bbls
6. Open the BOP and check for flow.
WELL CONTROL KILL SHEET
PRE-RECORDED PRE-RECORDED
ANNULUS DATA DRILL STRING DATA PUMP START-UP PROCEDURES
LENGTHS CAPACITIES
LENGTHS CAPACITIES (FT)
SURFACE STACKS
(BBLS/FT)
(FT) (BBLS/FT)
Drillpipe
DP x Casing
(1) Open the choke slightly while
observing casing pressure.
DP x OH Heavyweight
(2) Just as casing pressure begins to
decrease, start the kill pump.
Drill Collars
DC x OH
Page 118
x = (2) =
x
SUB SEA STACKS
x = (3) x =
(1) Open the choke slightly while
WELL CONTROL
x = =
Drill String Vol BBLS/STK (4) When the pump reaches KPR,
(3) Choke Line Volume (subsea only) Bit to Surface Strokes Annulus Stks
adjust the choke for the proper
= Drillpipe Pressure Schedule
x = Annulus Vol BBLS/STK
CASING Pipe designed to meet the requirements for setting at a specified depth
CEMENTING The process of displacing the casing annulus with cement to provide hydraulic integrity and
zone isolation
CEMENT CLASS
API provides nine classes of cement to allow for various pressure /depth /temperature conditions
Class Depth Range (ft)
.
A, B & C 0 - 6000
.
D 6000 - 10,000
.
E 10,000 - 14,000
.
F . 10,000 - 16,000
.
G&H 0 - 8000
.
J 12,000 - 16,000
.
Cement classes are modified with accelerators or retarders to adapt to job requirement
DENSITY RANGE
A wide range of cement slurry densities can be obtained using various additives
25
Slurry Density (ppg)
20
15
Densified
Weighted
10
Ultra Conventional Neat Heavily
Lightweight Lightweight weighted
5
L QUALITY CONTRO
TOTA L
Successful
Cement Job
Training Technology Techniques
Knowledge
Service Operator
Rig
Companies Contractor
Team Concept
Attitude Commitment Dedication Communication
CEMENTING PHILOSOPHY
Page 119
CASING CEMENTING
High gel strengths and yield point, high fluid loss, thick filter cake, high solids content, loss
POOR MUD circulation material, mud /cement compatibility
CONDITION
LOST Loss zones not sealed before cementing. Excessive circulating annulus pressure causes cement
CIRCULATION loss. Scratchers remove protective LCM
ABNORMAL Complicates well planning /drilling. Heavy tubulars reduce clearances, high density slurries
PRESSURE require more control, pipe movement more difficult, liner problems
.
SUBNORMAL Differential sticking, cement filtrate loss, low density slurries, reduced strength
PRESSURE
.
WATER Sands with clay sensitive to fresh water filtrate, water block in dry gas zones
SENSITIVE
FORMATION
.
HIGH Mud gelation, flash sets cement without retarder, casing elongation /contraction problems, down
TEMPERATURE hole tool limitations, cement strength retrogression
High displacement pump rates improve cement placement. Formation conditions determine the pump pressure window
Page 120
CASING CEMENTING
STANDARD EQUIPMENT
RUBBER PLUGS
(TOP & BOTTOM)
SCRATCHER
FLOAT COLLAR
CENTRALIZER
GUIDE SHOE
Page 121
CASING CEMENTING
Ensure casing is racked safely. Use adequate stripping for each casing layer to prevent bending /buckling. Rack casing with
collars toward V-door
Grades N-80 and higher should not be handled on metal racks and catwalks
Place casing on the racks in the proper order of running in. Verify mixed weights and grades are in the proper running order.
There must be no doubt as to the weight and grade of the casing. Unidentified joints should not be run
Ideally, the casing should be cleaned, inspected, measured and drifted before the next layer is placed on the rack
Remove thread protectors, clean the box and pin and protectors. Clean any debris from inside the casing . Reinstall clean pin
and box protectors hand tight
Any damaged joint and those that do not drift should be marked with red paint and laid aside
Four persons are required to measure casing. One person on each end of the tape, another in the center to prevent tape sag
and a fourth to visually check each call and record the measurement
Measure, record and number all joints, crossovers and in-string components to permit ready identification
Two or more of the heaviest weight joints should be held out to run at the top of the casing string to serve as a gauge ring and
for wear purposes
Measure several pin and threads of thread and coupled casing to determine the average thread length
Casing should arrive on location already electronically inspected and pressure tested
Page 122
CASING CEMENTING
Circulate hole until shaker is clean prior to pulling out of the hole to run casing
Make a wiper trip, above hole problem depths and check for cavings, tight spots, hole fill on bottom. Circulate bottoms up
checking for gas or water cut mud and mud losses. Stabilize any losses if possible before running casing
Measure the drill string while pulling out of the hole to obtain an accurate depth measurement
Condition the mud as required. This generally consists of lowering gel strengths, plastic viscosity and yield point, removing
drilled solids, lowering the fluid loss and improving wall cake properties
If a hole problem is encountered on the trip out, the problem must be corrected before running casing. Reaming and mud
conditioning until the hole stabilizes is the proper treatment
Record drag /set down trends on the trip out to run casing. These values will be used to evaluate the drag /set down trends
when the casing is on bottom and reciprocation begun
Select a competent casing shoe. Consider the casing strap and space out accordingly
At casing point TD, condition hole with GPM rates at least as high as the expected cementing pump rates
Page 123
CASING CEMENTING
Verify rating of substructure and traveling equipment is adequate to handle casing and cement load
Verify rating of substructure and traveling equipment is adequate to handle casing and cement load
Ensure elevator bails are of the proper length for the job
Ensure good condition of the drill line. Ensure proper number of block lines are strung to handle the casing hook load in air
Visually inspect dead line anchor, hook, traveling and crown blocks. Magna flux or ultrasonic inspection should be considered
for heavy hook loads
Visually inspect derrick pins and bolts for wear. Plumb derrick if necessary
Ensure mud pumps and centrifugal pumps are in proper working order
Rig tongs should be checked for correct head size and new tong dies installed if necessary
Visually inspect the slip bushing /bowl for proper operating condition
Ensure adequate size casing fill-up line with control valve is rigged up
Ensure adequate water storage available for cement job and possible loss of circulation
Page 124
CASING CEMENTING
Page 125
CASING CEMENTING
Observe correct make-up procedures. Ensure torque gauge on tongs is accurate. Use API thread compound
Ensure casing cementing head is properly dressed with top /bottom plugs and proper cross overs
Utilize a casing running schedule to monitor casing displacement trends for losses /gains
Run surge /swab pressure calculations. Communicate the proper running speed to the Driller. Running speeds of
0.75 - 1.5 ft/sec are typical
With conventional float equipment, break circulation after running the first 2 - 3 joints to verify proper working order
Apply thread lock compound to the pin ends of float equipment and shoe joints
Pick-up /set-down weights for casing string should be recorded for each joint for early detection of sticking
Bring casing string to a complete stop before setting slips. Do not allow elevators to get ahead of casing through tight spots
Fill casing every five joints minimum depending on casing size. Communicate fill-up schedule to casing crew
For surface wellheads, measure the last joint of casing in the hole to prevent a casing collar being located across the wellhead
Page 126
CASING CEMENTING
Design cement slurry for specific job using company or industry specifications
Design preflush /spacers to be displaced in turbulent flow. Contact time at the top of the pay zone should be a minimum of
10 minutes
Use same mix water and cement in testing that will be used on location
Check compatibility of cement slurry, drilling mud and spacers at room and bottom hole circulating temperatures
Go to cement company bulk plant to check quality control on cement blending operations
Batch mix all cement slurries if possible using ribbon or paddle type blenders. Do not use conventional jet type mixers for
cement slurries
On location, collect 1 gallon samples of dry cement and 2 gallon samples of mix water. Hold until out come of job is determined
Calculate cement volume to be pumped and volume of mixing water required to mix cement
Calculate time, volume and strokes to pressure equalization point after start of displacement
Calculate time, volume and strokes to bump plug. Same calculations should be made for stage collar cementing
Calculate time, volume and strokes required to displace pipe after casing is on bottom and to circulate one complete circulation
Estimate the annulus cement velocities anticipated during the various stages of the job
Double check all volume calculations with cement company representatives on location prior to cementing
Page 127
CASING CEMENTING
Page 128
CASING CEMENTING
Center surface casing strings in rotary immediately after plug is bumped and WOC
For mud line suspension systems, land out on the mud line hanger, open wash ports and circulate the annulus above the
hanger with sea water
Casing normally should be landed with the same hook load as cemented. The only slack-off weight should be what is
necessary to set the slips or hang the casing
For mud line suspension systems, the casing should be overpulled to a pre-determined value prior to setting the slips to
prevent buckling the landing joint
Check mud pit and BOP for cement contamination, address immediately
Ensure landing joint is compatible with slip and seal assembly, caliper casing OD
A wellhead manufacture's representative should be present for slip, packoff and casing head installation. Test casing head prior
to nippling up the BOP equipment
If temperature survey is run to locate cement top, check with cementing company for the recommended WOC time before
running
Clean casing head and flanges. Ring gasket and groove must be clean, dry and free of burrs or nicks. Do not grease the ring
gasket
All nuts and bolts should be clean and the correct size. All nuts should be tightened evenly for a proper seal
Check all nipples, valves and lines on the wellhead and BOP stack for correct pressure rating and proper test procedures
Cement drill-out practices should not jeopardize the integrity of the cement job
Do not impose any forces on the casing that would alter the cement bond. Do not enter the casing until the desired cement
strength is reached
Calculate the top plug depth and communicate data to the Driller before drill-out
Drill the plugs, float collar, cement and shoe with reduced weight and RPM to avoid shock loading the casing
A formation equivalency or leak-off test in the new hole is necessary to determine the effectiveness of the cement seal and the
formation fracture gradient
Page 129
CASING CEMENTING
CEMENT PROBLEM Monitoring cement jobs by continuously measuring pump rate, rate of returns, surface
densities and pressures can provide early detection of some cementing problems
DETECTION
Cement free-fall period remains longer than anticipated due to decreased annular pressure
UNSUSPECTED .
WELLBORE Surface pressures are lower than anticipated after free-fall
WASHOUT .
Reduced rate of returns when washout encountered followed by increased returns rate in
near gauge annulus
.
Erratic returns after free-fall period
Well goes on free-fall later and comes out of free-fall sooner than expected
DOWN HOLE .
RESTRICTIONS Surface pressures higher than expected
.
Rate of returns lower than anticipated during free-fall stages
.
Erratic rate of returns. First are higher than expected during deceleration, then level off
before coming out of free-fall
CEMENT Free-fall starts approximately when expected but ends prematurely due to higher frictional
SLURRY pressures
DEHYDRATION .
Surface pressures are higher than expected
.
Rate of returns normal until dehydration starts then begins to decrease
Page 130
HORIZONTAL DRILLING
HORIZONTAL WELL A wellbore drilled parallel the the bedding plane of a production zone
LIMIT PRODUCTION
OL OF UNWANTED
FLUIDS
MAXIMIZE
OL
PRODUCTION
OL L
PENETRATE
VERTICAL
FRACTURES
OL
INCREASE
PRODUCTION
OL LO
Page 131
LONG RADIUS MEDIUM RADIUS SHORT RADIUS
60' TO 20'
RADIUS
o o
1 To 4 /Ft
400 FT
700' TO 300'
RADIUS
o o
8 To 20 /100'
Page 132
2500 FT
HORIZONTAL WELL PORFILES
HORIZONTAL DRILLING
6000' TO 1000'
RADIUS
o o
1 To 6 /100'
4000 FT
HORIZONTAL DRILLING
BHA
ANGLE BUILDING ASSEMBLY
SHORT RADIUS KNUCKLE JOINT MEDIUM RADIUS DOUBLE BEND MOTOR
KICK BENT
PAD SUB
DUMP
KNUCKLE
VALVE
JOINT
MOTOR
SECTION
MOTOR
SECTION
ADJUSTABLE
BENT HOUSING
THRUST
BEARINGS THRUST
BEARINGS
ROTATING ROTATING
SPINDLE SPINDLE
DUMP
VALVE
MOTOR
SECTION
ADJUSTABLE
BENT HOUSING
THRUST
BEARINGS
ROTATING
SPINDLE
Page 133
HORIZONTAL DRILLING
Casing design
CASING .
Slotted liners
.
Predicted pick-up /slack-off weights
.
CEMENTING Slurry design Centralizers
.
Mud condition Pipe movement
.
Contamination
Page 134
Page 135
HORIZONTAL DRILLING
GAS
WELL CONTROL
HORIZONTAL WELL CONTROL KILL SHEET
(A) WELL DATA (C) CALCULATIONS (E) DRILLPIPE PRESSURE
SCHEDULE
Original Mud Weight (OMW) Kill Mud Weight (KMW) ppg
Kill Pump Rate (KPR) (FCP - KPP) x KOP (SIDPP x KOP INSTRUCTIONS
KCP = ICP + -
spm MD TVD
1. Record ICP, KCP, FCP, Stks to KOP and
Stks to Bit in spaces indicated.
.
Strokes to Bit
Page 136
X x 2. Calculate Strokes Increment to KOP.
= + .
stks - Stks to KOP 5= Stk Inc
.
From 0 stks, add Stks to each increment
Strokes to KOP until Stks to KOP is reached.
.
stks (D) WAIT & WEIGHT PROCEDURE 3. Calculate Strokes Increment to Bit.
.
.
From Stks to KOP, add these stks to each
(B) KICK DATA 1. Raise mud weight in pit to Kill Mud Weight value. increment until Stks to Bit is reached.
.
.
2. Monitor shut-in pressures for gas migration. If necessary, 4. Calculate drillpipe pressure reduction per
bleed mud to maintain SIDPP at initial shut-in value. increment from ICP to KOP.
.
Shut-In Drillpipe Pressure (SIDPP) . (ICP - KCP) 5= psi
.
3. Refer to Pump Start Up procedure, bring well on choke.
psi .
From ICP, subtract the pressure reduction
from each increment until KCP is reached.
4. Hold KPR constant and adjust the choke to maintain the .
Drillpipe Pressure Schedule until Kill Mud Weight returns. 5. Calculate drillpipe pressure reduction per
. increment from KCP to Bit.
.
Shut-In Casing Pressure (SICP) 5. Stop the pump, close the choke and check shut-in (KCP - FCP) 5= psi
.
psi pressures. Sub Sea Stack - Clear stack gas and kill riser. From KCP, subtract the pressure reduction
.
from each increment until FCP is reached.
6. Open the BOP and check for flow.
Pit Gain
bbls
HORIZONTAL WELL CONTROL KILL SHEET
LENGTHS CAPACITIES
(FT) (BBLS/FT) LENGTHS CAPACITIES
(FT) (BBLS/FT)
Drillpipe KOP
DP x Casing
Select the appro imate
MIDDLE of the kick-off
section
Heavyweight
DP x OH
Drill Collars
DC x OH
Page 137
(2) x = (1) Casing by Drill String Strokes to String Vol bbls/stk Stks to Bit
(1) Bit =
x =
(3) x =
x =
Bottoms Up Annulus Vol bbls/stk Annulus Stks
HORIZONTAL DRILLING
Page 138
INVESTIGATION PACKAGE
WELL: SHAKER HANDOVER DATE:
RIG: SHAKER MAN: MUD ENG:
LAST CSG OD: MD: HOLE SIZE:
EQUIPMENT STATUS
LOW SPEED SHAKERS HIGH SPEED SHAKERS HYDROCONES
SHAKER 1 SHAKER 2 SHAKER 1 SHAKER 2 DESANDER DESILTER CENTRIFUGE
DEGASSER
TIME OPERATION DEPTH CUTTING RET. *CUTTINGS *CUTTINGS WT. VIS WT. VIS COMMENTS
Dec / Nor / Inc TYPE DESCRIPTION IN IN OUT OUT
:00
:30
:00
:30
:00
:30
:00
:30
:00
:30
:00
:30
:00
:30
:00
:30
:00
:30
:00
:30
:00
:30
:00
:30
:00
* CUTTINGS TYPE: CLAY (CL), SHALE (SH), SAND (SD), GRAVEL (GVL), LIMESTONE (LS), SALT (SA), CEMENT (CMT), RUBBER (RUB), METAL (M)
* CUTTINGS DESCRIPTION: ROUND, FLAT CUTTINGS (CUT,R/F), SPLINTERY CAVINGS (CAV,S), BLOCKY CAVINGS (CAV,B), CLAY BALLS (CLBL), MUSHY CLAY (MSH)
NOTES:
Page 139
TIGHT HOLE / STUCK PIPE
WELL: REPORT DATE: REPORT
REPORT FORM
RIG: LOCATION: EVENT SEVERITY: TIGHT HOLE STUCK PIPE
.
WELL DATA: (when event occurred) Shoe Test: STRING DATA: Kelly Top Drive Rotating Mud Motor
. .
Csg Size: MD: TVD: Shoe Angle: Bit : Type: Size: BHA: Build Hold Drop
. .
Hole Size: MD: TVD: Last Trip MD: DC Size: Length: DC Size: Length:
. .
1 KOP MD: Deg/100': 2 KOP MD: Deg/100': Jar Size: Hyd. Mech. Trip Settings: UP Down:
. .
KOP Bottom 1 MD: KOP Bottom 2 MD: Angle TD: Jar Position (from bit): Tension Compression Neutral Point:
. .
Types & Depths of Problem Formation(s): Accelerator Position (from jar): HWDP Size: Length:
.
MUD DATA: (report ACTUAL mud properties) OPERATIONAL DATA: (directly before event occurred)
.
.
Mud Type: Wt: Fluid Loss: Rotating Wt: P/U Wt: S/O Wt:
.
.
Inhibitor Type: Concentration: CEC: RPM: Off/B Tq: WOB: On/B Tq:
.
.
Torque Trend:
Other: .
.
GPM: Cir Press: Press Trend:
Shaker Evidence: .
.
Other:
.
.
STICKING MECHANISM:
INDICATIONS: .
.
HOLE PACK-OFF/BRIDGE DIFFERENTIAL STICKING WELLBORE GEOMETRY
Operation When Event Occurred:
.
Page 140
.
Pipe Motion After Sticking: Down Possible Down Restricted Down Impossible Settled Cuttings Unconsolidated Form. Stiff Assembly
.
Reactive Shale Fractured/Faulted Form. Key Seat
Pipe Rotation After Sticking: Rot. Possible Rot. Restricted Rot. Impossible
. Geo-Pressured Shale Cement Blocks Micro Doglegs
Cir. Pressure After Sticking: Press. Normal Press. Restricted Cir. Impossible Hydro-Pressured Shale Soft Cement Ledges
.
Other:.
.
MUD DATA: (report ACTUAL mud properties) OPERATIONAL DATA: (when event occurred)
.
.
Mud Type: Wt: Fluid Loss: Operation: Depth Loss Started:
.
.
PV: YP: Gels: / / pH: O/W Ratio: GPM: Cir Press: ECD Loss Zone:
.
.
Slip-To-Slip Pipe Speed: Ft/Sec Max Csg Press Before Loss:
Inhibitor Type: Concentration: CEC: .
.
Other:
System LCM: Lbs/bbl Polymer Type: Lbs/bbl: Gel: Lbs/bbl .
.
Other:
.
..
Depleted Zone Unconsolidated Form. Fractured Form. Faulted Zone Vugular Form. Cavernous Zone Hole In Csg. Other:
MUD LOSS DATA: SEEPAGE = < 20 Bbls/Hr Partial = > 20 Bbls/Hr Total = No Returns
.
Depth: Bbls/Hr: GPM Static Loss: Bbls/Hr Depth: Bbls/Hr: GPM Static Loss: Bbls/Hr
.
Depth: Bbls/Hr: GPM Static Loss: Bbls/Hr Depth: Bbls/Hr: GPM Static Loss: Bbls/Hr
.
Page 141
Pill : WBM OBM Wt: Vol: Gel Content: Lbs/Bbl
.
Pill 2: WBM OBM Wt: Vol: Gel Content: Lbs/Bbl SPOTTING RESULTS: Successful Partially Successful Unsuccessful
.
.
Pill Type: LCM Cement Gunk Specialty Pill Other: Bbls Spotted: Depth: MD TVD Wait Time:
INVESTIGATION PACKAGE
.
.
Material: Fine Med Cor Lbs/Bbl: SQUEEZE RESULTS: Successful Partially Successful Unsuccessful
.
.
Material: Fine Med Cor Lbs/Bbl: Bbls Squeezed: Depth: MD TVD Press Held:
.
.
Wait Time: Notes:
Material: Fine Med Cor Lbs/Bbl:
.
Length: OD: ID: Wt/Ft: Grade: LOCATE: Cargo Manifest Supply Co Paper Work Operations Manual
. .
Conn Size / Type: Stress Relief: yes no Bore Restrictions: Inspection Report Fishing Dimensions Sheet Setting Calibrations Sheet
. .
H S/CO Resistant: yes no Oil Resistant: yes no Temp Limit: Batt. Life: MATCH SERIAL/MODEL ON TOOL WITH ALL PAPER WORK
.
.
Inspection
2 2 Report: yes no Settings & Calibrations:
. CORRECT TOOL INCORRECT TOOL
Other: . Comments:
.
OPERATIONS: INSPECTION:
. .
Special Handling / Operations / Maintenance: CHECK: Damaged Container Explosive/Corrosives Marked Battery pack
. .
. .
. INSPECT TOOL FOR: Thread Protectors Thread Damage Impact damage
Safety Recommendations:
. . Bent / Mashed Tube Water Damage Other:
Page 142
.
GPM Min: Max: Hydro Press Limit: Angle Limit: Operating Tools Crossovers Other:
.
. OPERATIONS:
Tools included w/shipment: yes no Available In Area: .
.
Fishing Records Available: yes no Fishing Dimension Sheet Shipped: yes no INSPECT: Tool Bore Access Ports Safety Clamps Tool Conn Size/Type
.
Lost-In-Hole Consequences:
. FUNCTION TEST: Valves Flappers Other:
SUPPL COMPAN RATING: Rep. Availability: -1 2 3 4 5 6+
.
.
WELL DATA: (when failure occurred) STRING DATA: Kelly Top Drive Rotating Mud Motor Shock Sub
.. .
Csg Size: MD: TVD: Shoe Angle: Bit : Type: Size: BHA: Build Hold Drop
.. .
Hole Size: MD: TVD: Angle TD: DC Size: Length: DC Size: Length:
.
..
Dogleg MD From: To: Deg/100': Jar Position (from bit): Accelerator Position (from jar):
.
.
Hole Washout %: MD From: To: Neutral Point: (from bit) HWDP Size: Length:
.
.
Other:
.
RECOVER :
OPERATIONAL DATA: (when event occurred) .
. Back-Up Tool: On-Site Available Delivery Time:
.
Operation:
. Spare Parts: On-Site Available Delivery Time:
.
Rotating Wt: P/U Wt: S/O Wt:
. Down-Time Hours: Supply Co Response Rating :123456 Not Applicable
.
Drag Trend:
. Other:
RPM: Off/B Tq: WOB: On/B Tq:
.
Torque Trend:
.
FAILURE DESCRIPTION:
.
Page 143
Failed Tool: Failed Part:
.
Describe Failure:
.
Cause(s):
.
INVESTIGATION PACKAGE
PREVENTIVE SUGGESTIONS:
WELL DATA: (when failure occurred) STRING DATA: Kelly Top Drive Rotating Mud Motor Shock Sub
.. .
Csg Size: MD: TVD: Shoe Angle: Bit : Type: Size: BHA: Build Hold Drop
.. .
Hole Size: MD: TVD: Angle TD: DC OD/ID: / Lbs/Ft: Conn Type: Length:
.. .
2 KOP/Dogleg MD From: To: Deg/100': Jar Position (from bit): Accelerator Position (from jar):
.
.
Hole Washout %: MD From: To: Neutral Point: HWDP Size: Conn Type: Length:
.
.
Other:
.
Page 144
Wt Ind Reading Failure: Tq Failure: Press Failure:
.
FAILURE DESCRIPTION:
.
TYPE OF FAILURE: DP Tube Fatigue BHA Conn Fatigue Connection Leak Sulfide Stress Crack Split Box Tension Torsion
.
Combination Tension/Torsion Collapse Burst Weld Failure Mechanical Failure Of String Equipment (Jar, M/Motor, Etc.):
.
Other:
.
DP Tube Failure: Inches From Box Pin Shoulder Serial : Last Insp. Date: Insp. Report : Rotating Hrs:
INVESTIGATION PACKAGE
.
BHA Conn Failure: Ft From Bit Comp Tension Serial s Of Joints: Pin Box Last Insp. Date(s): Rotating Hrs:
.
Conn Leak: DP HWDP DC Serial s Of Joints: Pin Box Last Insp. Date(s): Rotating Hrs:
.
PREVENTIVE SUGGESTIONS:
.
KICK DATE: TIME: ORIG. MW: KILL MW: PIT GAIN: DRILLING REPORT :
WELL DATA: (when event occurred) Shoe Test: STRING DATA: Kelly Top Drive Rotating Mud Motor DS Float Valve
.. .
Csg Size: MD: TVD: Shoe Angle: DC OD/ID: / Ft: DC OD/ID: / Ft:
.. .
Hole Size: MD: TVD: Angle TD: HWDP OD: Lbs/Ft: Ft:
.. .
Kick Tolerance: Shallowest Abnormal FP (>9.0 PPGE): TVD DP OD/Wt: / Ft: DP OD/Wt: / Ft:
.
.
Form. Press TD: Other: SS Choke Line ID: Ft: Pressure Loss: SPM:
.
.
Other:
.
Mud Type: WBM OBM/SBM Wt In: Wt Out: Slip-To-Slip Trip Speed: Out: Min In: Min Other:
.
Kick Warning Signs: Drilling Break Well Flow Pit Gain Cir Pressure Loss Incorrect Hole Fill Volume Total Loss Of Cir Gas Sea Surface
.
Other:
.
Cause Of Kick: Drilled High Press Zone Light Mud Wt Pumped Total Loss Of Cir Cut Mud Wt (water,oil, gas) Swabbing Improper Hole Fill Procedure
.
Other:
.
SHUT-IN DATA: Time Of Kick: On Bottom
Drill String: Off Bottom Bit MD: Out Of Hole
.
Shut-In Procedure: Soft Hard Fast BOP Closing Pressure: SIDPP: SICP: Pit Gain:
.
Page 145
Kick Type: Under Balance Kick Induced Kick Kick Fluid Type: Water Oil Gas Unknown TVD Of Kick: yes
Gas Migration Observed: no
.
Other:
.
KILL OPERATION DATA: Pre-Kill Operation: Snub In Strip In Heavy Mud Cap Other:
.
Kill Procedure: Wait & Weight Method Circulation Method Volumetric Method Bullhead Other:
. .
Kill MW: Kill Pump Rate: SPM Safety Factor (if any), Added MW: Added Back Press: Other:
.