B T U E A I L D M W I E P L L N G L A H N P R O L O B E L E M L O S S
C I R T C W E L L C O ON T N R O OL RIG
R
REPAIR
P EQUI RE U L I A F
L DRIL G N I R S T
N G L L I I L D R R S J A R Z G N H O L I N L I L D R
G S I N N T A E C E M C K U C S T I P E P
IN K T O L I S ES S C E UC C S U
TABLE OF CONTENTS TEAM BUILDING PRINCIPLES TEAM BUILDING PRINCIPLES .......................................... ......................................................................................... ....................................................... ........
1
WELL PLAN BASIC GEOLOGY ..................................................................................................
2
CASING PROGRAM ..............................................................................................
9
DRILLING FLUIDS ................... ............................. .................... .................... .................... .................... .................... .................... ................. .......
15
HYDRAULICS HYDRAULICS PLANNING .................... .............................. .................... .................... .................... .................... ..................... .............. ...
20
STUCK PIPE HOLE PACK-OFF/BRIDGE ....................................................................................
22
DIFFERENTIAL STICKING ....................................................................................
44
WELLBORE GEOMETRY .................... .............................. .................... ..................... ..................... .................... .................... .............. ....
47
STUCK PIPE FREEING .........................................................................................
53
LOST CIRCULATION CIRCULATION LOST CIRCULATION MECHANISMS ....................................................................
56
SEEPAGE LOSS SOLUTIONS .............................................................................. PARTIAL LOSS SOLUTIONS ............................. .............. ............... ............... ............... ............... ......
60 61
TOTAL TOTAL LOSS SOLUTIONS ............... ............... ............... ............... ............... ........
61
PILL SPOTTING GUIDELINES GUIDELINES .................... .............................. .................... .................... .................... .................... ................. .......
63
RIG REPAIR IMPACT OF UNSCHEDULED RIG REPAIR ..........................................................
66
INTERGRATING PMP WITH WELL PLAN ............................................................
68
DRILLING SYSTEM EMERGENCY PROCEDURE................................................
69
DOWN HOLE EQUIPMENT FAILURE TOOL FAILURE CAUSES .....................................................................................
70
FACTORS INFLUENCING TOOL SELECTION .....................................................
71
RIG-SITE TOOL SELECTION / INSPECTION .......................................................
72
DRILL STRING FAILURE DRILL PIPE FAILURE PREVENTION PLAN .........................................................
73
DRILL PIPE TUBE FATIGUE FAILURE .................................................................
74
BHA CONNECTION FATIGUE FAILURE ...............................................................
77
BHA CONNECTION STRESS RELIEF / BSR ........................................................
78
DRILL CREW FIVE SECOND CHECKS ................................................................
79
DRILL STRING CARE & HANDLING HANDLING PRACTICES .............................................. .............................................. 80
TABLE OF CONTENTS
DRILLING JARS BASIC JAR OPERATIONS............. OPERATIONS.......................................... .......................................................... ......................................... ............ PUMP OPEN FORCE FORCE ............................ ......................................................... .......................................................... ................................ ... COCKING /TRIPPING /TRIPPING THE JAR ............................ ......................................................... ............................................. ................ DRILLING ACCELERATOR ACCELERATOR ................................................ ............................... JAR RULES / PLACEMENT GUIDELINES ........................................................
81 82 83 86 87
WELL CONTROL PRIMARY WELL CONTROL ............................................................................ ................................................................................ ....
91
SWAB / SURGE PRESSURE ...................................................... .............................................................................. ........................
92
SECONDARY SECONDARY WELL CONTROL ....................................................... ........................................................................ .................
95
KICK DETECTION / SHUT-IN TEAM ................................................................... ...................................................................
97
TERTIARY WELL WELL CONTROL ............................................................... .............. 111 KICK OBM DETECTION / GAS BEHAVIOR BEHAVIOR ........................................... ........... 115 WELL CONTROL KILL SHEET .......................................................................... 117
CASING /CEMENTING CEMENTING CONSIDERATIONS CONSIDERATIONS ............................... ...................................... 119 STANDARD EQUIPMENT .................................................................................. 121 EQUIPMENT /WELLBORE PREPARA PREPARATIONS TIONS ..................................................... ..................................................... 122 CASING PRE JOB CHECKLIST .................................................................. .......................................................................... ........ 125 RUNNING CASING GUIDELINES ....................................................................... ....................................................................... 126 CEMENTING PRE JOB CHECKLIST .................................................................. .................................................................. 127 TROUBLE SHOOTING CEMENTING PROBLEMS ............................................
130
HORIZONTAL DRILLING WHY DRILL HORIZONT HORIZONTAL AL WELLS ...................................................... .................................................................... .............. 131 HORIZONT HORIZONTAL WELL PROFILES ...................................................... ......................................................................... ................... 132
HORIZONTAL HORIZONTAL DRILLING BHA ......................... ................................................ .. 133 HORIZONTAL HORIZONTAL WELL PLANNING ............................ ......................................................... ............................................ ............... 134 HORIZONTAL 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 CIRCULATION REPORT FORM ....................................................... ............................................................... ........ 141
EQUIPMENT SELECTION / INSPECTION FORM ............................................ 142 DOWN HOLE TOOL FAILURE FAILURE REPORT FORM ................................................. ................................................. 143 DRILL STRING FAILURE FAILURE REPORT FORM ......................................................... ......................................................... 144 WELL CONTROL EVENT REPORT FORM ......................................................... ......................................................... 145
TEAM BUILDING PRINCIPLES TEAMS
WHAT ARE TEAMS Two or more people working together Work teams have a common goal Team members develop "earned trust" through accountability Teams are self-motivated Teams are performance motivated MULTI-FUNCTIONAL
TEAMS REQUIRE A MIXTURE OF SKILLS Technical expertise Functional experience Problem solving capability Decision making skills Inter-personal skills PROBLEM SOLVING
HOW DO TEAMS SOLVE PROBLEMS Define the problem Identify primary cause(s) Develop alternative solution(s) Implement action plans Evaluate the effectiveness of the plan WORKING STYLES
TEAM DECISION MAKING STYLES COMMAND Decision is made by leader CONSULTATIVE Decision is made by leader with team input CONSENSUS Decision is made as a team DELEGATION Decision is delegated down the chain of command RESULTS
WHAT WHAT TEAMS DO IMPROVE WORK QUALITY - More expertise/skills are available FLEXIBLE - Respond quickly to change CREATIVE CREATIVE - Continously iimprove mprove work processes DEVELOP AND IMPLEMENT ACTION PLANS - Better communications REDUCE PROJECT COST
Page 1
WELL PLAN
BASIC GEOLOGY
The study of the earth's composition, structure and history
GEOLOGY
An extensive depression in the earth's surface
SEDIMENTARY BASIN FORMATION
An estimated 90% of the worlds dri lling occurs in offshore and inla nd basins A laterally continuous seq uence of sediments that is recognizably distinct an d mappable
ORIGIN OF SEDIMENTARY ROCK Land mass elevated above sea level is weathered and broken down to small fragments (clastics):
WEATHERING
Mechanically by water, wind and temperature Chemically by soluble minerals dissolving into the water
TRANSPORTATION
Rock fragments (sand, silt, clay) and dissolved chemical compounds (silicates, calcite, iron, etc.) are transported to the basin by gravity, flowing water and wind
SEDIMENTATION
The fragments fragments are swept into into the basin where they settle settle to the floor floor of the basin and form water saturated beds of sand and clay
EVAPORATION
WEATHERED ROCK
S E DI M ME N E NT A T T I I O N
SEDIMENTARY ROCKS
IGNEOUS ROCK
BASIN
COMPACTION CEMENTATION
BASIN
GULF OF MEXICO PERMIAN BASIN TRINIDAD
The weight of each successive sediment layer (overburden) compacts the sediments below. Compaction squeezes the water out of the sediments and back to the sea
As the water water is squeezed out, out, the dissolved dissolved chemical compounds left behind cements cements the fragments together to form sedimentary form sedimentary rock
RELATIVE ABUNDANCE OF SEDIMENTARY ROCK SHALE SANDSTONE 30% 60% 30% 10% 50% 50%
LIMESTONE 10% 60% -----
Shale, sandstone, sandstone, limestone limestone / dolomite dolomite generally generally make up about 99% of sedimentary sedimentary rock, all other rocks total only +/- 1%
Page 2
WELL PLAN
BASIC GEOLOGY
STANDARD GEOLOGIC CODES & DESCRIPTION 1 micron (m) = 1 millionth of a meter. meter. Sizes of common materials materials in microns: beach sand -70m; minimum visual visual sensitivity - 30m; minimum touch sensitivity sensitivity - 20m; red blood cells - 7m.
ROCK
ABV CODE GRAIN SIZE
CLAYSTONE CLst Sh & SHALE
Less than 4 microns
MARL
Mrl
Less than 4 microns
SILTST SILTSTONE ONE
SLst SLst
4 to 60 microns
DESCRIPTION Rocks formed from an accumulation of clay minerals and silt size particles
Rocks formed from an accumulation of clay minerals and calcite (calcium carbonate)
Rocks formed from an accumulation of mineral grains (quartz).
SANDST SANDSTONE ONE
Sst
60 microns to 2mm
Sandstone compressive strength, +/- 9000 psi
CONGLO CONGLOMER MERA ATE
Cgl
Greater than 2mm
Rocks formed from an accumulation of primarily gr anule, pebble and boulder size particles
LIME LIMEST STON ONE E
Ls
DOLO DOLOMI MITE TE & CHALK
Dol Dol Chk
Rocks formed from large deposits of primarily calcite (calcium carbonate) and dolomite (calcium magnesium) Chemical Rocks
Compressive strengths: Limestone, +/- 20,000 psi; Dolomite, +/- 24,000 psi; Chert, +/- 83,000 psi; Chalk, +/+/- 6000 psi; CHERT
Gypsum & Anhydrite
Cht
Gyp Anhy Evaporates
SALT
BASEM ASEMEN ENT T
Rocks composed of minerals that precipitated from solution during the evaporation of water Compressive strength: strength: Anhydrite +/- 6000 psi
Sa
Bm
VOLC VOLCAN ANIC ICS S
Volc olc
FAULT
Flt
OIL
O
GAS
G
WATER
Wtr
Igneous rock
L T U A F
A geologic feature
Rock formed from the cooling of molten magma
A fracture in the rock caused by natural forces forces resulting in failure and displacement of the formation along the fault plane
Liquid hydrocarbon (5.0 to 7.1 ppg) Native formation fluids None
Gaseous hydrocarbon (2.3 ppg average) Water (8.3 to 11.7 11.7 ppg)
Page 3
WELL PLAN
BASIC GEOLOGY
CHARACTERISTICS OF SEDIMENTARY ROCKS The percent of void per 100% volume volume
POROSITY ( O )
Sedimentary Sedimentary rocks (shale, (shale, sandstone, sandstone, limestone) limestone) always always exhibit exhibit some value of porosity porosity TYPICAL POROSITY REDUCTION BY SEDIMENT COMPACTION AND CEMENTATION
FORMATION POROSITY NO FILTER CAKE
0
5
) ' 0 0 0 1 ( 10 H T P E 15 D
SAND
20
FLUID TRAPPED IN PORE SPACES
SHALE
SHALE
WELLBORE
NOTE: Deviations from the average porosity can occur at any depth
25 0
10
20
30
40
50
POROSITY %
The ability of a rock to flow fluids measured in units of darcies
PERMEABILITY (K)
A rock that is porous does not indicate th at it is permeable ( i.e., shale with 10% poro porosi sity ty may may exhi exhibi bitt only only micro perm permea eabi bili lity ty,, 10-6 to 10-12 darc darcy) y)
TYPICAL PERMEABILITY REDUCTION BY SEDIMENT COMPACTION AND CEMENTATION
FORMATION FORMATION PERMEABILITY
NATURAL CEMENT
FLUID LOSS
0
FILTER CAKE
) ' 5 0 0 0 1 ( 10
SANDS
SHALES
H T P E 15 D
20
CONNECTEDPOROSITY PROVIDES PERMEABILITY
SANDSTONE
WELLBORE
NOTE: Deviations from the average permeability is possible at any depth
25 0
1
2
3
4
PERMEABILITY (Darcies)
Page 4
5
WELL PLAN
BASIC GEOLOGY
SOURCES OF ROCK STRESS A force imposed imposed to the rock matrix measured in pounds of force force per square inch of area (psi)
ROCK STRESS
Natural sources of rock stress originate from overburden stress, tectonic stress and formation fluid pressure
OVERBURDEN STRESS
The stress produced by the combined weight of the rocks and formation fluids overlaying a depth of interest TYPICAL OVERBURDEN STRESS VERSUS DEPTH 0
3 ) ' 0 0 0 1 ( H T P E D
VERTICAL STRESS OF OVERBURDEN
12.5 ppg
HORIZONTAL STRESS OF OVERBURDEN
12.5 ppg
6 9 12 15
14.0 ppg
18 10
12
14
16
18
20
OVERBURDEN STRESS ppg
Generated by the force of gravity, 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)
The stress produced by lateral (side to side) forces in the formation
TECTONIC STRESS
Tectonic stresses are usually very high in mountainous regions
SIDE VIEW
S T R E S S
C I C O N T C T E
TOP VIEW
ACTUAL HOLE DIAMETER
Tectonic stressed shale generally produces an oval shaped wellbore
Page 5
WELL PLAN
BASIC GEOLOGY
RELATIVE STRENGTH OF SEDIMENTARY ROCK Formation fracture strength is defined by the overburden stress, cementation, formation pressure and the strength of the rock type. The followin following g compares compares the relative relative strength strength of the differen differentt rock types (all othe otherr factors factors conside considered red equa equal) l)
HIGH
MEDIUM
0
Lbs
Max
0
SANDSTONE
Lbs
VERY HIGH
Max
SHALE
0
Lbs
Max
LIMESTONE
Of the three three primar primary y rock rock types, types, Sandstone genera generally lly exhibi exhibits ts the lowest lowest compre compress ssive ive and tensil tensile e streng strength th
RELATIVE CHARACTERISTICS OF SEDIMENTARY ROCK ROCK TYPE
DIVISION
CHARACTERISTIC Generally occurs in the shallower depth(< 10,000') Soft and pliable due to high water content
SOFT (Ductile)
Fracture and injection pressure approximately same Pliable texture allows fractures to "heal" quickly Associated with with swabbing, lost circulation, hole wash-out, wash-out, hole pack-off pack-off
SHALE HARD (Brittle)
Generally occurs in deeper depth (10,000' +) Hard and brittle due to low w ater content Fracture pressure higher than injection pressure Brittle texture prevents fracture from "healing" Associated with hole hole pack-off/bridge pack-off/bridge Generally occurs in the shallower depth(< 5,000')
UNCONSOLIDATED
High permeability (2 darcies +) Associated with with lost circulation, circulation, hole wash-out, wash-out, hole pack-off pack-off
SANDSTONE CONSOLIDATED
LIMESTONE/ DOLOMITE
High porosity (25% +)
SOFT (Chalk) HARD (Brittle)
Generally occurs in mid to deep depths (4000' +) Porosity range (25% - 1%) Permeability range (2 darcies - 10 milidarcies) Associated with differential differential sticking, underguage hole hole Low compressive strength High porosity (+/- 40%) Permeability range (2 darcies - 10 milidarcies) Will dissolve in fresh water muds Associated with with hole wash-out, mud contamination High compressive strength, usually fractured High porosity (20 - 40%), High permeability Associated with pack-off/bridge, pack-off/bridge, lost circulation, circulation, differential sticking sticking
Page 6
WELL PLAN
BASIC GEOLOGY
FORMATION FLUID PRESSURE CLASSIFICATIONS FORMATION FLUID PRESSURE
The pressure of the native fluids (water, oil, gas) in the pore spaces of the rock Formation pressure equal to a full column (surface to depth of interest) of formation water
NORMAL
NORMAL FORMATION PRESSURE VERSUS DEPTH 0
1 FORMATION FLUID MIGRATING TO SURFACE
) t f3 0 0 0 1 ( 4 H T P E D 5
. 4 6 5 P S I / F T
6
7 0
TRANSITION SHALE
1 2 3 4 5 FORMATION PRESSURE (1000 psi)
Normal formation pressure is calculated: Normal FP
= .465 X Vertic Vertical al Depth ft Unless better information is known, .465 psi/ft is a safe world-wide average psi
Formation pressure greater than the normal pressure expected for the depth of interest
ABNORMAL
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 6
ABNORMAL / SUBNORMAL FORMATION PRESSURE VERSUS DEPTH NORMAL FP
7 TRANSITION SHALE (Permeability (Permeability Barrier)
ABNORMAL FP
N O R M A L F P L I N E
8
) t f 0 0 0 1 ( H T P E D
9
10
DEPLETED 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.)
SUBNORMAL
Formation pressure less than the normal pressure expected for the depth of interest Lower-than-normal formation pressure may exist in offshore basins due to production depletion, howe howeve verr, naturally occurring subn subnor orma mall pres pressu sure re is rare rare.. In inla inland nd basi basins ns,, nati native ve subn subnor orma mall pressure is a common occurrence
Page 7
WELL PLAN
BASIC GEOLOGY
RESERVOIR TRAPS
SOURCE ROCK RESERVOIR ROCK RESERVOIR TRAP STRUCTURAL TRAP
The bed of sediments in which the oil and gas was produced (shale, limestone). Compaction squeezes the oil and gas to the reservoir rock (primary migration) The permeable formation which receives and stores the oil and gas volume of primary migration The elevation in reservoir rock to which the oil and gas accumulates (secondary migration) Traps formed as a result of uplifting, folding and/or faulting of the formation layers
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
RESERVOIR ROCK
M S E GI C R O A N T D I O A N R Y
OIL M P R I I G M R A A R T I Y O N
WATER
OIL & GAS IN PORE SPACES
SOURCE ROCK
FAULT TRAP
GAS
Traps formed by the displacement of the reservoir rock along a stress crack which positions the face of the down-dip section against impermeable rock
D I S P L A S E A LE D C E F AU M LT P E LAN N E T
OIL
WATER
STRATIGRAPHIC TRAP
Traps formed by a permeable reservoir rock grading to a non-permeable rock or the termination of a reservoir rock
GAS
SANDSTONE GRADES TO CLAY
OIL WATER
SANDSTONE PINCH OUT
Page 8
WELL PLAN
CASING PROGRAM SYSTEM FUNCTIONS
FUNCTIONS OF THE CASING SYSTEM
SECTIONS:
FUNCTIONS:
Drive or Structural Casing
* INTEGRITY
PROVIDE HYDRAULIC
* Circulation * Well Control * Production
Surface Casing
*
PROTECT THE WELLBORE * High Formation Formation Pressure Pressure * Fluid Kicks
Intermediate Casing
* Formation Instability
Liner Tie Back Casing
*
PROTECT THE FORMATION * High Wellbore Wellbore Pressure * Incompatible Incompatible Wellbore Fluids * Production Production Zone Isolation
Production Liner or Casing
PRODUCTION ZONE
PRODUCTION ZONE
SHALE
Page 9
WELL PLAN
CASING PROGRAM
CASING CASING POINT POINT SELECT SELECTION ION
HYDRAULIC INTEGRITY
Shoe strength must support the hydrostatic, circulating and surge pressures and provide a sufficient kick tolerance for well control safety
SOLUTION FOR DRILLING PROBLEMS
In some instances, the only solution to a drilling problem may be to run casing before the planned shoe depth is reached. reached. This could be the next planned casing string or a contingency liner
ZONE ISOLA I SOLATION TION
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 cementing
SUITABLE 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 permea permeabilit bility y is present, present, the true leak-off leak-off pressure pressure of of the the wellbore wellbore is diffic difficult ult to establi establish sh 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 selected for the seat is usually the best compromise between the ideal and what is possible
DRIVE / STRUCTURAL CASING Depending on the depth of the surface sediments, the setting depth of the pipe may range from less than 100 feet to 400 feet + below the mud line / surface
DRIVE PIPE
To insu insure re seat seat inte integr grit ity y, the the pipe pipe is driven to refusal , indi indica cate ted d by the the numb number er of hamm hammer er blows per foot (BPF) of penetration, For example, the US Gulf coast coast requires 140 to 150 BPF, in Venezuela, 250 BPF
STRUCTURAL CASING
The planned setting depth of the casing may range from 100 feet to 1500 feet + below the mud line / surface depending on anticipated hole instability and / or lost circulation problems
Surface Sediments
DATA:
FUNCTIONS:
PIPE SIZES
9-5/8" - 36"
DRIVE PIPE (Driven to Refusal)
Recycling Returns Diverter system
*
STRUCTURAL CASING (Drilled (Drilled and Cemented)
Prevent Rig Foundation Washout
Vertical Pilot Structural Support * Conductor Conductor casing casing
SHUT-IN NOT RECOMMENDED
* Wellhead Wellhead * BOP Equipm Equipment ent
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 SURFACE CASING
Planned setting depth determined by anticipated hole instability, lost circulation problems 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:
EXTEND HYDRAULIC INTEGRITY
PROTECT FORMATIONS:
PIPE SIZE 7" - 20"
FUNCTIONS:
CEMENTED BACK TO SURFACE OR TO THE SHOE
CASING PRESSURE TESTED
*
Fresh water sands
*
Low / High Wellbore Pressure
*
Hydraulic Erosion
SOLUTION FOR DRILLING PROBLEMS:
*
Lost Circulation
*
Formation Instability
SHOE PRESSURE TESTED
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 CASING
FUNCTIONS:
DATA:
Planned setting depth determined by minimum desired kick tolerance, anticipated hole instability, instability, lost circulation problems
PROVIDE WELL CONTROL CAPABILITY
SOLUTION FOR DRILLING PROBLEMS:
PIPE SIZE 5" - 13-3/8"
CEMENTED BACK TO PREDETERMINED DEPTH
CASING PRESSURE TESTED
SHOE PRESSURE TESTED
*
Lost circulation
*
Formation Instability
*
Differential Sticking
PROTECT FORMATIONS:
*
Low / High Wellbore Pressure
*
Incompatible Wellbore Fluids
*
Production Zone Isolation
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, instability, lost circulation problems or protecting production zones If the liner is contingent on drilling problems, occurrence of the problem determines the setting depth
FUNCTIONS:
DATA:
PROVIDE WELL CONTROL CAPABILITY
SOLUTION FOR SPECIFIC DRILLING PROBLEMS:
PIPE SIZE 5" - 11-3/4"
* Lost circulation
* Formation Instability
CEMENTED BACK TO LINER HANGER
* Differential Sticking
PROTECT FORMATIONS:
* Low / High Wellbore
LINER PRESSURE TESTED
Pressure
* Incompatible Wellbore Fluids
SHOE PRESSURE TESTED
* Production Zone Isolation
SHUT-IN RECOMMENDED
The liner is pressure tested and the shoe and liner top tested to a maximum anticipated pressure or to leak-off
Page 13
WELL PLAN
CASING PROGRAM
PRODUCTION LINER / CASING OR TIE-BACK CASING
PRODUCTION LINER
Planned setting depth determined by total depth of the well (TD)
FUNCTIONS:
DATA:
PROVIDE PROVIDE WELL CONTROL CAPABILITY
PROVIDE PROVIDE A STABL STABLE E WELLBORE:
PIPE SIZE 5" - 9-5/8"
CEMENTED BACK TO PREDETERMINED DEPTH
LINER / CASING / TIEBACK CASING PRESSURE TESTED
Well Testing
*
Production Operations
*
Protects Intermediate casings
PRODUCTION PRODUCTION ZONE ISOLATION:
Production Production Zone
Production Zone Shale The casing, tie-back casing, liner and top are tested to a maximum anticipated pressure
Page 14
*
*
Selective Testing
*
Dual Completions
WELL PLAN DRILLING FLUID
DRILLING FLUIDS
A fluid used to perform various functions during a drilling operation
FUNCTIONS OF THE DRILLING FLUID FUNCTION
PROPERTY
WELL CONTROL
Fluid weight
HOLE STABILITY
HOLE CLEANING
TRANSMIT HYDRAULIC HORSEPOWER HORSEPOWER TO BIT
FORMATION EVALUATION EVALUATION
MUD TYPE DRY AIR / GAS MIST FOAM AERATED AERATED MUD
MUD TYPE NATIVE GEL BENTONITE BENTONITE/CHEMICAL
RESULTING EFFECT Primary control of formation fluid flow into the wellbore
Chemically - Mud Inhibition Mechanically - Fluid Weight
Minimize formation reaction Prevents hole cave-in/collapse Suspend and carry cuttings/cavings from the wellbore and release the solids at surface
Yield Point (YP) Gel Strength Mud weight Base fluid of the mud
Remove cuttings from below bit face to improve penetration rate
Mud system type and properties
Gather and interpret data Provide early warning signs of problems
TYPE TYPES S OF DRILL DRILLING ING FLUID FLUIDS S AIR / GAS FLUIDS APPLICATION
ADVANTAGE / DISADVANTAGE
Drilling hard dry formations Drilling lost circulation zone
Increase penetration rate Minimum formation damage Continuous gas/oil detection
WATER BASE FLUIDS APPLICATION
ADVANTAGE / DISADVANT DISA DVANTAGE AGE
Low cost spud mud Non-weighted system Base for more sophisticated systems
Most versatile system Products readily available Basic system
LIGNITE/ LIGNOSULFONATE (DISPERSED)
Filtration control Tolerance to contaminants Applicable at all mud weights
Easily maintained Reduced penetration rate
INHIBITIVE (SALTS) POLYMERS
Drilling water sensitive shales
MUD TYPE DIESEL OIL SYNTHETIC OIL
OIL / SYNTHETIC BASE FLUIDS APPLICATION Drilling water sensitive shales Drilling water soluble formations Reduce stuck pipe potential Corrosive environment High bottom hole temperature
Page 15
Controls chemical reaction of shales Improved penetration rate
ADVANTAGE / DISADVANT DISA DVANTAGE AGE Completely inhibited system Improved penetration rate Formation stability Torque & drag reduction Environmental concerns High cost Logging/ cementing concerns
DRILLING FLUIDS
WELL PLAN DRILLING FLUID SELECTION CRITERIA
The selected drilling fluid is usually the best compromise of the available choices
CRITERIA WELL TYPE (Exploratory / Development)
RESOURCE
RESULT
Seismic data Offset data Field experience Mud company records
An "overkill" mud mud system is generally selected for exploratory wells The optimum mud system is selected on development wells
ENVIRONMENTAL
Regulatory requirements requirements
May limit the choice of mud systems
WELL CONTROL REQUIREMENTS
Seismic data evaluations Offset well data Field experience Mud company records
The mud system must be capable of minimum to maximum mud weight requirements
HOLE STABILITY Chemical / Mechanical
Seismic data evaluations Offset well data Field experience Mud company records
An inhibited system is selected to avoid chemical reaction with water sensitive shales and water soluble formations (salt, anhydrite) The mud system must be capable of minimum to maximum mud weight requirements
TEMPERATURE/ CHEMICAL STABILITY OF THE MUD
Offset well data Field experience Mud company records
The mud system must tolerate formation temperatures without chemical break down Must tolerate contamination from formation fluids, minerals and solids
OPTIMUM DRILLING AND ECONOMIC PERFORMANCE
Offset well data Field experience Mud company records Bit company records
The mud system system should provide an an acceptable penetration rate with minimum formation damage at the lowest cost
BASE FLUID / MUD PRODUCT AVAILABILITY
Offset well data Mud company records
May limit the choice of mud systems in remote areas
Contractor inventory Field experience
May limit the choice of mud systems in remote areas
RIG EQUIPMENT
Page 16
WELL PLAN
DRILLING FLUIDS
DRILLING FLUID CONTAMINANTS CONTAMINANT
Any undesirable component that causes a detrimental affect to the drilling fluid
CONTAMINANT DRILL SOLIDS
EXAMPLE Active solids - Clays Inactive solids - Silt, sand, sand, limestone, limestone, chert, chert, etc.
EVAPORITE SALTS
Sodium chloride, NaCl Potassium chloride, KCl Calcium chloride, CaCl2 Magnesium chloride, MgCl2 Anhydrite, CaSO4
WATER FLOWS
Mixed salts at various concentrations
ACID GASES
Carbon dioxide, CO2 Hydrogen sulfide, H2S
HYDROCARBONS
TEMPERATURE CEMENT
Light or heavy oils Lignite Coal Degradation of mud products Result of cementing operations
DRILLING SOLIDS CLASSIFICATIONS CLASSIFICATIONS DRILL SOLIDS
CLASSIFICATION CLASSIFICATION BY PARTICLE SIZE
COARSE
Greater than 2,000 microns
INTERMEDIATE
Between 250 and 2,000 microns
MEDIUM
Between 74 and 250 microns
FINE
Between 44 and 74 microns
ULTRA-FINE
Between 2 and 44 microns
COLLOIDAL
Less than 2 microns
SOLIDS REMOVAL EQUIPMENT EQUIPMENT SHALE SHAKERS
SOLIDS REMOVED Down to 150 microns with 200 mesh screens
DESANDER
Down to 50 to 70 microns (cone size dependent)
DESILTER
Down to 20 to 40 microns (cone size dependent)
MUD CLEANER CENTRIFUGE
Down to 74 microns Colloidal solids up to 5 microns
Page 17
WELL PLAN
DRILLING FLUIDS
WATER BASE MUD (WBM) TREND ANALYSIS TREND
Changes in mud properties are an indication that something abnormal is taking place
MUD PROPERTY
TREND CHANGE INCREASE
MUD WEIGHT DECREASE
FUNNEL VISCOSITY
PLASTIC VISCOSITY
POSSIBLE CAUSE Drill solids increase, Heavy spot from barite sag, Over treatment during weight-up Formation fluid influx, Light spot from barite sag, Excessive Excessive water additions additions
INCREASE
Reactive shale drilled, drilled, Drill solids solids increase, increase, Low water content, Calcium contamination from cement, Anhydrite formation drilled
DECREASE
Formation water influx, influx, Excessive Excessive water content
INCREASE
Unconsolidated sand drilled, Drill solids increase, Low water water content
DECREASE
Formation water influx, Excessive Excessive water additions, Solids content decrease
INCREASE
Reactive shale shale drilled, Anhydrite Anhydrite formation formation drilled, Low water content, Calcium contamination from cement
DECREASE
Formation water influx, Excessive Excessive water additions, Decrease in low gravity gravity solids, Additions of chemical thinners thinners
INCREASE
Reactive shale drilled, Low water water content, Calcium contamination contamination from cement, or anhydrite formation drilled
DECREASE
Formation water influx, Excessive Excessive water additions, Additions of chemical thinners
INCREASE
Low gravity solids increase, Flocculation from cement, cement, chloride, calcium contamination, Low gel content
DECREASE
Mud treatment taking affect
YIELD POINT
GEL STRENGTH
API / HPHT FLUID LOSS
pH
CHLORIDE
TOTAL HARDNESS
INCREASE
Addition of pH control control additives, Calcium contamination contamination
DECREASE
Addition of mud products, Anhydrite Anhydrite formation drilled
INCREASE
Salt formation formation is drilled, Pressure transition transition shale is drilled, Formation water influx
DECREASE
Water additions
INCREASE
Salt or calcium formation formation is drilled, Formation water influx
DECREASE CATION EXCHANGE CAPACITY (CEC)
Addition of fresh fresh water, Chemical addition
INCREASE
Reactive shale is drilled, Addition of bentonite bentonite
DECREASE
Water additions, additions, Solids removal equipment
Page 18
WELL PLAN
DRILLING FLUIDS
OIL / SYNTHETIC BASE MUD (OBM / SBM) TREND ANALYSIS TREND
Changes in mud properties are an indication that something abnormal is taking place
MUD PROPERTY
INCREASE
Drill solids increase, Heavy spot from barite sag, Over treatment during weight-up
DECREASE
Formation Formation water water influx, Excessive base base oil additions, additions, Light spot from barite sag
MUD WEIGHT
PLASTIC VISCOSITY
POSSIBLE CAUSE
TREND CHANGE
INCREASE
Addition of water, water, calcium calcium carbona carbonate, te, primary primary emulsifier emulsifier,, Low gravity gravity solids solids increase
DECREASE
Addition of base oil, Decrease Decrease in low low gravity gravity solids
INCREASE
Increase in organophilic clay, clay, Additions of emulsified water or synthetic polymer
DECREASE
Addition of base oil or degellant, degellant, Decrease Decrease of organoph organophilic ilic clay
INCREASE
Addition of organophilic organophilic gel, Addition of water water
DECREASE
Large base oil additions, Increase in mud temperature
CHANGE
Large addition of water or water influx, Large additions of base oil, High bottom hole temperature
INCREASE
Increase in emulsifier concentration, Adding wetting agent or base oil
DECREASE
Decrease in emulsifier concentration, Newly prepared OBM has low ES but increases with time
INCREASE
Water % of O/W ratio decreasing, Addition of calcium chloride
YIELD POINT
GEL STRENGTH
OIL / WATER RATIO
ELECTRICAL STABILITY (ES)
WATER WATER PHASE PHAS E SALINITY
DECREASE
HPHT FLUID LOSS
EXCESS LIME
Water % of O/W ratio increasing from water addition or formation water influx
INCREASE
Addition of base oil, Decrease Decrease in emulsifier emulsifier concentr concentration, ation, Water Water present present in filtrate
DECREASE
Increase in primary emulsifier concentration
INCREASE
Addition of lime, Drilling calcium calcium formation formation (anhydrite) (anhydrite)
DECREASE
CO2 or H2 S kick, Additions of base oil or water
Page 19
WELL PLAN
HYDRAULICS PLANNING
DRILLING OPTIMIZATION OPTIMIZATION PLANNING SEQUENCE GEOLOGY OPTIMIZE MUD TYPE AND PROPERTIES OPTIMIZE BIT SELECTION OPTIMIZE BIT HYDRAULICS OPTIMIZE BIT WEIGHT AND RPM DEFINE RIG EQUIPMENT REQUIREMENTS /CAPABILITY DEVELOP ACTION PLANS FOR WELL
The calculated balance of the hydraulic components that will sufficiently sufficiently clean the bit and wellbore with minimum horsepower
HYDRAULICS OPTIMIZATION
CONSIDERATIONS CONSIDERATIONS FOR HYDRAULICS PLANNING FACTOR
CONSIDERATION
MAXIMIZE RATE OF PENETRATION (ROP)
In medium to hard formations, maximize hydraulic horsepower to increase penetration rate
MAXIMIZE HOLE CLEANING
In soft formations and high angle holes, maximize flow rate for hole cleaning
In small and/or deep holes, limit flow rate to minimize annulus friction pressure and reduce the potential for:
ANNULUS FRICTION PRESSURE
Lost Circulation; Circulation; Differential Sticking; Hole Instability Instability In soft, unconsolidated formations, limit flow rate to minimize turbulence in the annulus if hole wash-out is a problem
HYDRAULIC EROSION
Larger jet sizes may be required if there is potential for lost circulation
BIT PLUGGING
FACTORS FACTORS THAT AFFECT HYDRAULICS
EQUIPMENT
WELLBORE
PUMP PRESSURE / VOLUME OUTPUT
DEPTH / HOLE SIZE / MUD TYPE
DRILL STRING ID, OD, LENGTH
MUD WEIGHT / RHEOLOGY
DOWN HOLE EQUIPMENT RESTRICTIONS
ANNULUS FRICTION PRESSURE
BIT TYPE / JETS
HOLE PROBLEM POTENTIAL
Page 20
WELL PLAN
HYDRAULICS PLANNING
RULES FOR OPTIMIZING HYDRAULICS FLOW RATE RATE
Maintain Maintain 30 to to 60 60 GPM GPM per inch of bit diameter diameter
Do not violate the flow rate rule to get more horsepower, jet velocity 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 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
HYDRAULIC HORSEPOWER HORSEPOWER
Maintain 2.5 to 5 hydraulic horsepower per square inch 2 of bit diameter (HHP/In (HHP/In ) 2
Hydraulic horsepower is based on hole size / ROP. ROP. Large bits require more HHP/In 2
Fast drilling requires the maximum HHP/In, even above 5 HHP/In
2
2
Maximum HHP/In should be considered when pump horsepower is available available Do not waste fuel and wear on the pumps with excessive pressure pressure Many rigs do not have enough horsepower to provide the recommended HHP/In
BIT PRESSURE DROP
2
Design hydraulics for 50% to 65% pressure drop across the bit
Nozzle velocity velocity (ft/sec) - The velocity of the fluid exiting exiting the bit jets 35% to 50% of pump pressure is lost lost through the drill string and annulus. Hydraulic calculations 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 operate below 30 GPM per inch of bit diameter
JET VELOCITY VELOCITY
Maintain Maintain jet velocity velocity between between 350 and 450 feet per second second
Impact Force - The product of fluid fluid jet velocity velocity and fluid weight. Impact is the the force the drilling fluid exerts to to the formation to assist bottom hole cleaning Jet velocity will influence chip-hold-down and penetration rate Do not operate with a jet velocity below 250 ft/sec 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) 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 penetration rate versus using using two jets
Page 21
STUCK PIPE
HOLE PROBLEMS
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
DIFFERENTIAL DIFFERENTIAL FORCE
SETTLED CUTTINGS
STIFF ASSEMBLY KEY SEAT
SHALE INSTABILITY UNCONSOLIDATED FORMATIONS
MICRO DOGLEGS
FRACTURED FORMATIONS
LEDGES
CEMENT RELATED
MOBILE FORMATIONS
JUNK
UNDERGAUGE HOLE
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
HOLE PACK-OFF CAUSES
HOLE BRIDGE CAUSES
SETTLED CUTTINGS
SHALE INSTABILITY
SHALE INSTABILITY REACTIVE SHALE GEO-PRESSURED GEO-PRESSURED SHALE HYDRO-PRESSURED HYDRO-PRESSURED SHALE OVER BURDEN STRESS TECTONIC STRESS
OVER BURDEN STRESS TECTONIC STRESS
UNCONSOLIDATED FORMATIONS
UNCONSOLIDATED FORMATIONS
FRACTURED FORMATIONS FORMATIONS
FRACTURED FORMATIONS FORMATIONS
SOFT CEMENT
CEMENT BLOCKS JUNK
Page 22
STUCK PIPE
HOLE PACK-OFF
HOLE PROBLEMS
CAUSES OF SETTLED CUTTINGS HOLE CLEANING IS AFFECT ED BY 6 BASIC FACTORS AFFECT
FACTOR
RATE OF PENETRATION
Determines the cuttings volume in returning mud
HOLE STABILITY
Cavings load added to to the returning mud
ANNULAR VELOCITY
Lifts the Lifts the cuttings
MUD RHEOLOGY
Suspend and Carry the cuttings
CIRCULATING TIME
Transport the the cuttings to surface
HOLE ANGLE
Reduces the Reduces the ability to clean the hole
SETTLED CUTTINGS, NEAR VERTICAL WELLBORE (< 35 ) 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 PACK-OFF THE DRILL STRING S T R I N G
WARNING: HIGH ROP, LOW PUMP RATE, LITTLE TO NO CIRCULATING TIME AT CONNECTIONS
R O
T
A T I O N
TORQUE, DRAG AND PUMP PRESSURE INCREASE C I R C U L A T I O N
OVERPULL OFF SLIPS, PUMP SURGE TO BREAK CIRCULATION CIRCULATION FILL ON BOTTOM INDICATIONS: LIKELY TO OCCUR ON CONNECTIONS, POSSIBLE DURING TRIP CIRCULATION CIRCULATION RESTRICTED OR IMPOSSIBLE
O V E R P U L L ! !
P A C O F K F ! !
FIRST ACTION: APPLY LOW PUMP PRESSURE (200 - 400 psi) APPLY TORQUE TORQUE AND JAR DOWN WITH MAXIMUM TRIP LOAD
ST UC K!!
CIRCULATE CIRCULATE CLEAN TO AVOID RECURRENCE PREVENTIVE ACTION: CONTROL ROP, ROP, MAXIMIZE ANNULAR VELOCITY MAINTAIN SUFFICIENT GEL STRENGTH AND YP CIRCULATE CIRCULATE 5 TO 10 MINUTES BEFORE CONNECTIONS CIRCULATE CIRCULATE HOLE CLEAN B EFORE POOH
Page 23
STUCK PIPE
HOLE PROBLEMS
HOLE PACK-OFF PACK-OFF
SETTLED CUTTINGS, HIGH ANGLE WELLBORE (>35 )
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 THAN 35 DRILLING WITH A DOWN HOLE MOTOR CUTTINGS BED FORM WHILE DRILLING
HIGH ROP, LOW PUMP RATE, INCREASE TORQUE & DRAG, INCREASING PUMP PRESSURE
STR I NG
INCREASE OVERPULL ON TRIPS R O T ACTION ACTION
C I R R C U L A T I O N
INDICATIONS:
LIKELY TO OCCUR WHILE POOH, POSSIBLE WHILE DRILLING CIRCULATING CIRCULATING PRESSURE RESTRICTED OR IMPOSSIBLE
O V E R P U L L ! !
FIRST ACTION:
APPLY LOW PUMP PRESSURE (100 - 400 psi) JAR DOWN WITH MAXIMUM TRIP LOAD, APPLY TORQUE WITH CAUTION S T U C K ! !
CLEAN HOLE TO AVOID RECURRENCE PREVENTIVE ACTION:
RECORD TREND INDICATORS FOR INADEQUATE INADEQUATE HOLE CLEANING
CUTTINGS BED
CONTROL ROP, MAINTAIN MUD PROPERTIES, CIRCULATE AT MAXIMUM RATE, MAXIMIZE STRING ROTATION
PACK OFF!!
CIRCULATE CIRCULATE HOLE CLEAN BEFORE POOH, ESTABLISH AN OVERPULL LIMIT USE LOW VIS/HIGH DENSITY SWEEPS
Page 24
STUCK PIPE
HOLE PACK-OFF
DRILLER TRENDS DRILLING CONNECTION
DRAG
HOLE PROBLEMS
INDICATIONS INDICATIONS OF SETTLED CUTTINGS TORQUE PRESSURE
Increasing, erratic
Increasing, erratic
Overpull off slips
OTHER
Increasing
Pressure surges Gradual decrease in ROP
Surge to start circulations
Back pressure before breaking connection Back flow
TRIPPING OUT
Increasing, erratic Overpull off slips
Swabbing
TRIPPING IN
Increasing set down weight Overpull off slips
Begins with BHA below depths of 35 hole angle
BACK REAMING
Overpull off slips Erratic overpull
PUMPING OUT
Overpull off slips Increasing, erratic
Increasing, erratic
Increasing
Surge to start circulation String pistoning Loss of fluid possible
Increasing
Surge to start circulation String pistoning, Loss of fluid possible
RIG TEAM INDICATIONS INDICATIONS SHAKER TRENDS
Low cuttings return return rate for penetration penetration rate, Erratic cuttings returns, returns, No cuttings return, High cuttings return on fine shaker shaker screen and desilter / mud cleaner cleaner
LOGGER TRENDS
Rounded, reground cuttings
MUD TRENDS
Increasing plastic plastic viscosity and yield point, point, Increase in low gravity gravity solids, Possible mud weight increase
PREVENTIVE ACTION Maintain the required mud properties Circulate at maximum recommended GPM for hole size 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 Wipe the hole hole at full circulating rate rate as long long as possi possible ble (5 - 10 min) min) before before connec connectio tions, ns, Rotat Rotate e at maximu maximum m RPM when when possib possible le Maxi Maximi mize ze stri string ng moti motion on when when circ circul ulat atin ing g the the hole hole clea clean. n. Use maximum practical RPM, RPM, rais raise e the the dril drilll stri string ng slow slowly ly (5 min/ min/st std) d) and and slack slack-of -offf at a safe but fast fast rate rate (1 min/s min/std) td) Consider pumping high-vis sweeps in low angle wells (<35 ). Consider low-vis / high-vis sweeps sweeps in higher angle wells (>35 ) DO NOT STOP CIRCULATING UNTIL ALL SWEEPS RETURN Circulate until the hole is clean, If the last sweep brings up excessive amounts of cuttings, continue continue with hole cleaning operations, Several circulations may be necessary
Page 25
STUCK PIPE
HOLE PROBLEMS
HOLE PACK-OFF
MINIMUM GPM
VERSUS HOLE SIZE AND HOLE ANGLE MINIMUM GPM VERSUS 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
35 - 55
1250 GPM
950 GPM
650 GPM
450 GPM
1100 GPM
750 GPM
500 GPM
55 +
Minimum flow rate (GPM) for any given hole size and angle is greatly dependent on mud weight, mud rheology and annulus geometry. geometry. Maximum recommended flowrate is 60 GPM per inch of bit diameter
MINIMUM ROP
VERSUS HOLE SIZE AND HOLE ANGLE MAXIMUM ROP VERSUS 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
60
75
100
55 +
Pene Penetr trat atio ion n rate rate guid guidel elin ines es are are base based d on adequate mud mud prop proper erti ties es
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 INTERVAL 0 - 35
2
1.7
1.4
1.4
35 - 55
2.5
2.5
1.8
1.6
3
2
1.7
55 + PROCEDURE:
1. Separate the wellbore into sections sections by hole angle from intervals above. above. 2. Multiply each hole section section length (Sect. Lth) by CSF and total total the adjusted measured depth (MD). (MD). Adjusted MD = (Sect. Lth X CSF) + (Sect. Lth X CSF) + (Sect. Lth X CSF) 3. Calculate the minimum circulating circulating strokes to c clean lean the hole.
Minimum Circ Stks =
Total Adjusted Adjusted MD x Bottoms-Up Bottoms-Up Stks Measured Depth
Page 26
STUCK PIPE
HOLE PACK-OFF
HOLE PROBLEMS EXAMPLE CALCULATION CALCULATION
MINIMUM CIRCULATING STROKES CALCULATION (12-1/4" HOLE) SEPARATE THE WELLBORE INTO SECTIONS BY HOLE ANGLE INTERVALS o
o
o
o
o
55 +
35 To 55
0 To 35
6500' To 13,000' = 6500'
4500' To 6500' = 2000'
0' To 4500' = 4500' = 4500'
o
o
0 To35 0' To To 4500' 4500'
o
o
35 To To 55 4500' To 6500'
o
55 + 6500' To 13,000'
MULTIPLY EACH HOLE SECTION LENGTH BY CSF AND TOTAL THE ADJUSTED MEASURED DEPTH ADJUSTED MD
= (SECT LTH LTH 1x CSF) + (SECT LTH LTH x CSF) + (SECT LTH LTH x CSF)
=
(4500 (4500 x 1.4) 1.4) + (2000 (2000 x 1.8) 1.8) + (6500 (6500 x 2)
=
6300 6300 + 3600 3600 + 13,0 13,000 00
=
22,9 22,900 00 TOTAL TOTAL ADJUSTED MD
CALCULATE THE MINIMUM CIRCULATING STROKES REQUIRED TO CLEAN THE HOLE MIN CIR STKS
TOTAL TOTAL ADJUSTED ADJUSTED MD MD x BOTTOMS-UP STKS * MEASURED DEPTH 22,900 x 15,000 = 13,000
=
=
26, 26,423 423 STROKES
*CURRENT BOTTOMS UP STROKES
Page 27
HOLE PROBLEMS
STUCK PIPE HIGH ANGLE HOLE CLEANING CLEANING GUIDELINES (> 35 )
DRILLING
CONNECTIONS
TRIPPING
Page 28
HOLE PACK-OFF
STUCK PIPE
HOLE PACK-OFF
HOLE PROBLEMS
SHALE INSTABILITY INSTABILITY The shale formation becomes unstable, breaks apart and falls into the wellbore
CHEMICALLY STRESSED
MECHANICALLY STRESSED GEO-PRESSURED SHALE
REACTIVE SHALE
HYDRO-PRESSURED HYDRO-PRESSURE D SHALE
OVERBURDEN STRESS
TECTONIC STRESS
CHEMICALLY CHEMICALLY STRESSED SHALE
REACTIVE SHALE SHALE BREAKING APART
1 DAY EXPOSURE
WATER ABS ABSORBED
CAUSE:
WATER SENSITIVE SHALE DRILLED WITH LITTLE OR NO MUD INHIBITION SHALE ABSORBS WATER AND SWELLS INTO THE WELLBORE
B Y 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 3 DAYS EXPOSURE
CLAY BALLS
OVER PULL & SWABBING BHA BALLING (MUD RINGS) INDICATIONS:
GENERALLY OCCURS WHILE POOH, POSSIBLE WHILE DRILLING CIRCULATION IMPOSSIBLE OR HIGHLY RESTRICTED FIRST ACTION:
APPLY LOW LOW PUMP PRESSURE (200 (200 - 400 PSI) L L U P R E V O
P A O F C K F ! !
IF POOH, TORQUE UP AND JAR DOWN WITH MAXIMUM TRIP LOAD
5 DAYS EXPOSURE ! K ! C U S T
IF RIH, JAR UP WITH MAXIMUM TRIP LOAD, DO NOT APPLY TORQUE PREVENTIVE ACTION:
USE AN INHIBITED MUD MAINTAIN MUD PROPERTIES PLAN WIPER TRIPS MINIMIZE HOLE EXPOSURE TIME
Page 29
STUCK PIPE
HOLE PROBLEMS
DRILLER TRENDS DRILLING CONNECTION
DRAG
INDICATIONS INDICATIONS OF REACTIVE CUTTINGS TORQUE PRESSURE
Increasing Smooth
Increasing, Smooth
Increasing, Smooth Overpull off slips
TRIPPING IN
Increasing set down weight Overpull off slips
BACK REAMING
Overpull off slips
PUMPING OUT
Increasing, Smooth Overpull off slips
Increasing
Surge to start circulation
Overpull off slips
TRIPPING OUT
HOLE PACK-OFF
OTHER
Pressure surges Gradual decrease in ROP Mud loss possible Back pressure before connection Back flow Swabbing Begins at depth of problem formation Mud loss possible
Increasing, Smooth
Increasing
Surge to start circulation String pistoning Loss of mud
Increasing
Surge to start circulation String pistoning, Loss of mud
RIG TEAM INDICATIONS SHAKER TRENDS
Soft clay balls. Wet "mushy" "mushy" clay (gumbo). Flow line plugging plugging
LOGGER TRENDS
Large quanty of hydrated shale cuttings. cuttings. High value on shale swelling test test
MUD TRENDS
High funnel vis. & YP YP.. Increasing PV, PV, low gravity solids & CEC. Possible mud weight increase. Low inhibitor content
PREVENTIVE ACTION Addition Addition of various various salts salts (potassium, (potassium, sodium, calcium, calcium, etc.) to reduce reduce the chemical chemical attraction attraction of water water to to the shale shale Addition Addition of various various encapsulati encapsulating ng (coating) (coating) polymers polymers to reduce reduce water water contact contact with the shale shale Use of oil and synthetic base muds to exclude water contact with the shale Minimize open hole time Plan regular wiper / reaming trips based on time, footage drilled or the warning signs of reactive shale Ensure adequate hydraulics for bit and hole cleaning Maintain required mud properties and minimize low gravity solids
Page 30
STUCK PIPE
HOLE PACK-OFF
HOLE PROBLEMS MECHANICALLY MECHANICALLY STRESSED SHALE
GEO-PRESSURED SHALE
HYDROSTATIC PRESSURE 5000 PSI
FORMATION PRESSURE
5500 PSI
WARNING: 5000 PSI
STRESS!! HSP
SIGNS BEGIN TO OCCUR AS SHALE IS DRILLED
5500 PSI Pore Pressure
MUD LOGGER TRENDS INDICATE INCREASING PORE PRESSURE
S t r e s s C r a r a c k
ROP INCREASE WHEN FIRST DRILLED Hole Wall
TORQUE INCREASE & DRAG ON CONNECTIONS HOLE FILL ON CONNECTIONS, BRIDGES ON TRIPS, SPLINTERY SHALE CAVINGS POSSIBLE BACKGROUND GAS INCREASE INDICATIONS:
LIKELY TO OCCUR WHILE TRIPPING, POSSIBLE WHILE DRILLING
! ! L L U P R E V O
COMPLETE PACK-OFF LIKELY, HOLE BRIDGING POSSIBLE CIRCULATION RESTRICTED OR IMPOSSIBLE
FIRST ACTION:
P A O F C K F ! !
APPLY APPLY LOW PUMP PRESSURE (200 - 400 psi)
K ! ! C S T U
APPLY APPLY TORQUE, JAR DOWN WITH WITH MAXIMUM TRIP LOAD
PREVENTIVE ACTION:
ADJUST MUD WEIGHT WEIGHT BEFORE DRILLING KNOWN PRESSURED SHALE SLOWLY INCREASE MUD WEIGHT TO STABILIZE SHALE MINIMIZE SWAB / SURGE PRESSURES MINIMIZE OPEN HOLE EXPOSURE TIME
Page 31
STUCK PIPE
HOLE PROBLEMS
HOLE PACK-OFF
MECHANICALLY STRESSED SHALE
HYDRO-PRESSURED SHALE CAUSE:
OVER TIME, SHALE PORE PRESSURE BECOMES CHARGED BY HYDROSTATIC OVER BALANCE
STABILIZED SHALE
FORMATION PRESSURE
HYDROSTATIC 5000 PSI
4000 PSI
DRILL STRING MOTION AND WELLBORE PRESSURE SURGES STRESS-CRACKS THE UNSTABILIZED SHALE THE SHALE FALLS INTO THE WELLBORE AND JAMS THE STRING
WARNING:
GENERALLY FOLLOWS A MUD WEIGHT REDUCTION TORQUE & DRAG INCREASE DAYS OF EXPOSURE
0
2 4 6 8
UNSTABILIZED SHALE
SHALE CAVINGS AT SHAKER
INDICATIONS:
POSSIBLE WHILE DRILLING OR TRIPPING
4000 PSI
INVASION!!
HSP INVASION!! 5000 PSI
HOLE BRIDGING OR COMPLETE PACK-OFF POSSIBLE CIRCULATION RESTRICTED OR IMPOSSIBLE
FIRST ACTION:
APPLY APPLY LOW PUMP PRESSURE (200 - 400 psi) APPLY APPLY TORQUE, JAR DOWN WITH MAXIMUM TRIP LOAD CIRCULATE AT MAXIMUM RATE ONCE CIRCULATION IS ESTABLISHED
! ! L L U P R E V O
P A C K O F F ! !
PREVENTIVE ACTION:
USE OBM, SBM OR GLYCOL BASE MUD IF PROBLEM IS SUSPECTED
! ! ! K U C S T
IF A MUD WEIGHT REDUCTION IS NECESSARY, REDUCE GRADUALLY OVER SEVERAL CIRCULATIONS MINIMIZE WELLBORE PRESSURE SURGES
Page 32
STUCK PIPE
HOLE PACK-OFF
HOLE PROBLEMS
MECHANICALLY MECHANICALLY STRESSED SHALE
OVERBURDEN STRESS CAUSE:
MUD WT. 12.5 PPG
STABILIZED SHALE
HSP
MUD WEIGHT IS INSUFFICIENT TO SUPPORT THE OVER BURDEN
N r E e D v R o U B
MUD WEIGHT IS NOT ADJUSTED AS HOLE ANGLE INCREASES INCREASES 0
12.0 PPGE
90 STRESS
STRESSED SHALE FRACTURES AND FALLS INTO THE WELLBORE
G E P P 0 .0 1 3
S T 4 R E 5 S S
WARNING:
0
HOLE CLEANING PROBLEMS 0
0
0
0
0
INCREASE TORQUE & DRAG
20
14.0
SHALE CAVINGS AT SHAKER
PPGE
INDICATION:
CAN OCCUR WHILE DRILLING OR TRIPPING HOLE BRIDGING OR PACK-OFF POSSIBLE RESTRICTED CIRCULATION OR NO CIRCULATION POSSIBLE
FIRST ACTION:
APPLY APPLY LOW PUMP PRESSURE (200 - 400 psi)
N r E e D v R o U B
! ! L L U P R E V O
UNSTABILIZED SHALE!!
0 .0 1 3
0
90 STRESS
12.0 PPGE MUD WT. 12.5 PPG
APPLY APPLY TORQUE, JAR DOWN WITH MAXIMUM TRIP LOAD
G E P P
S T 4 R E 5 S S
0
PREVENTIVE PREVENTIVE ACTION:
USE MUD WEIGHT NEEDED TO STABILIZE THE OVER BURDEN
0
0 S T U C K ! !
14.0
INCREASE MUD WEIGHT AS HOLE ANGLE INCREASES
PPGE 0
45 0
0
Page 33
STUCK PIPE
HOLE PACK-OFF
HOLE PROBLEMS
MECHANICALY MECHANICALY STRESSED SHALE
TECTONIC STRESS
CAUSE:
NATURALLY OCCURRING LATERAL FORCES IN THE FORMATIONS STRESSED SHALE FRACTURES, FALLS INTO THE WELLBORE AND JAMS THE DRILL STRING SANDSTONE SQUEEZES IN CAUSING UNDER GAUGE HOLE
!! S T R E S S C T E T E C T O N I C
WARNING:
MOUNTAINOUS LOCATION PROGNOSED TECTONICS ERRATIC TORQUE & DRAG BLOCKY SHALE CAVINGS CREATES ELLIPTICAL WELLBORE
INDICATIONS:
POSSIBLE WHILE DRILLING OR TRIPPING
! ! L L U P R E V O
G NG Z I I N E Z E E QU UE S Q
SHALE CAVING IN
CIRCULATION RESTRICTED OR IMPOSSIBLE
FIRST ACTION:
APPLY APPLY LOW PUMP PRESSURE (200 - 400 psi) APPLY APPLY TORQUE, JAR DOWN WITH MAXIMUM TRIP LOAD
E! ! N E O T S D S AN
PREVENTIVE ACTION:
INCREASE MUD WEIGHT IF POSSIBLE CIRCULATE HIGH DENSITY SWEEPS MINIMIZE WELLBORE PRESSURE SURGES MINIMIZE OPEN HOLE EXPOSURE TIME
B R I D DG I N N G ! ! !
S T U C K ! ! !
Page 34
STUCK PIPE
HOLE PROBLEMS
DRILLER TRENDS DRILLING CONNECTION TRIPPING OUT
TRIPPING IN
DRAG
HOLE PACK-OFF
INDICATIONS OF MECHANICALLY STRESSED SHALE TORQUE OTHER PRESSURE
Increasing, erratic
Increasing, erratic
Increasing
Surge to start circulation
Overpull off slips
Increase ROP followed by gradual decrease, Pressure surges Hole fill
Increasing, erratic Overpull off slips
Swabbing
Increasing set down weight
Begins at depth of problem formation Hole fill on bottom
BACK REAMING
Overpull off slips
PUMPING OUT
Increasing, erratic Overpull off slips
Increasing, erratic
Increasing
Surge to start circulation String pistoning Loss of fluid possible
Increasing
Surge to start circulation String pistoning Loss of fluid possible
RIG TEAM INDICATIONS SHAKER TRENDS
Large, splintery or blocky shale cavings. Large volume of cavings
LOGGER TRENDS
Large quantity of splintery or blocky cavings with striations. striations. Possible indications of increase increase in formation pressure. Prognosed mechanically mechanically stressed stressed shale
MUD TRENDS
Possible slight increase in mud weight and plastic viscosity
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 sensitive shales AVOID AVOID MUD WEIGHT WEIGHT REDUCTION after after 1+ day exposure to hydrostatically hydrostatically sensitive shale. If mud weight reduction is necessary 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 Maintain mud properties to ensure hole cleaning Use sweeps to help clean the hole Stop drilling until the hole is circulated clean Minimize open hole exposure time Plan contingency to case-off the problem
Page 35
STUCK PIPE
HOLE PROBLEMS
HOLE PACK-OFF BRIDGE
UNCONSOLIDATED FORMATI FOR MATION ON CAUSE:
LITTLE OR NO FILTER CAKE UNBONDED FORMATION (SAND, PEA GRAVEL, ETC.) CAN NOT BE SUPPORTED BY HYDROSTATIC OVERBALANCE SAND/PEA GRAVEL FALLS INTO THE HOLE AND PACKS OFF THE DRILL STRING
WARNING:
LIKELY TO OCCUR AS THE FORMATION IS DRILLED SEEPAGE LOSS LIKELY INCREASE TORQUE & DRAG, PUMP PRESSURE FLUCTUATIONS HOLE FILL ON CONNECTIONS & TRIPS SHAKER & DESANDER OVER LOAD
! ! L L U P R E V O
INDICATIONS:
GENERALLY OCCURS IN SURFACE HOLE CAN OCCUR WHILE DRILLING OR TRIPPING SUDDEN PACK-OFF WITHOUT WARNING CIRCULATION IMPOSSIBLE
FIRST ACTION:
APPLY APPLY LOW PUMP PRESSURE (200 - 400 psi) JAR DOWN WITH MAXIMUM TRIP LOAD, APPLY APPLY TORQUE WITH WITH CAUTION
PREVENTIVE ACTION:
PACK OFF!!
K ! ! C U S T
CONTROL FLUID LOSS TO PROVIDE AN ADEQUATE ADEQUATE FILTER FILTER CAKE CONTROL DRILL SUSPECTED ZONE USE HIGH VIS SWEEPS SPOT A GEL PILL BEFORE POOH MINIMIZE TRIP SPEED
Page 36
STUCK PIPE
HOLE PACK-OFF / BRIDGE
DRILLER TRENDS DRILLING CONNECTION TRIPPING OUT
TRIPPING IN
DRAG Increasing, erratic
HOLE PROBLEMS
INDICATIONS INDICATIONS OF UNCONSOLIDATED FORMATION TORQUE OTHER PRESSURE Increasing, erratic
Increasing
Surge to start circulation
Overpull off slips
Pressure surges
Hole fill
Increasing, erratic Overpull off slips
Swabbing
Increasing set down weight
Begins at depth of problem formation Hole fill on bottom
BACK REAMING
Overpull off slips
PUMPING OUT
Increasing, erratic Overpull off slips
Increasing, erratic
Increasing
Surge to start circulation String pistoning Loss of fluid possible
Increasing
Surge to start circulation String pistoning, Loss of fluid possible
RIG TEAM INDICATIONS SHAKER TRENDS
Large volume of sand over shakers. shakers. Sand trap and desander overload
LOGGER TRENDS
Large quantity of sand in samples. samples. Prognosed unconsolidated unconsolidated formation
MUD TRENDS
Increase in mud weight and plastic viscosity. viscosity. High % sand content
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 Use sweeps to help keep the hole clean Be prepared for shaker, desilter, desilter, desander overloads Minimize seepage loss with fine lost circulation material through these intervals
Page 37
STUCK PIPE
HOLE PROBLEMS
HOLE PACK-OFF / BRIDGE
FRACTURED FORMATION
CAUSE:
NATURALLY FRACTURED FORMATIONS PIECES OF FORMATION FALL INTO THE WELLBORE AND JAM THE DRILL STRING
WARNING:
PROGNOSED FRACTURED LIMESTONE, LIMESTONE, SHALE AND/OR, FAULTS LIKELY TO OCCUR AS FORMATION IS DRILLED MUD LOGGER FORMATION EVALUATION BLOCKY CAVINGS AT SHAKER HOLE FILL ON CONNECTIONS AND TRIPS
! ! L L U P R E V O
INDICATIONS:
LIKELY DURING TRIPS, POSSIBLE WHILE DRILLING SUDDEN AND ERRATIC TORQUE AND DRAG LIKELY JUST BEFORE STRICKING CIRCULATION MAY BE RESTRICTED
FIRST ACTION:
B R RI ID G GE D E ! !!
DO NOT APPLY TORQUE, JAR DOWN WITH MAXIMUM TRIP LOAD CIRCULATE HIGH DENSITY HIGH VISCOSITY SWEEPS
FRACTURED LIMESTONE
! ! K C U T S
SPOT ACID IF STUCK IN LIMESTONE
PREVENTIVE ACTION:
CIRCULATE HOLE CLEAN BEFORE DRILLING AHEAD MINIMIZE SEEPAGE LOSSES SLOW TRIP SPEED BEFORE BHA ENTERS SUSPECTED ZONE
Page 38
STUCK PIPE
HOLE PACK-OFF / BRIDGE
DRILLER TRENDS DRILLING
DRAG Sudden, increasing, erratic
HOLE PROBLEMS
INDICATIONS INDICATIONS OF FRACTURED FORMATION TORQUE PRESSURE Sudden, erratic
No change No change
Overpull off slips
OTHER
Hole fill
CONNECTION TRIPPING OUT
TRIPPING IN
Increasing, erratic Overpull off slips Increasing set down weight
BACK REAMING
Overpull off slips Increasing, erratic
PUMPING OUT
Overpull off slips Increasing, erratic
Begins at depth of problem formation Hole fill on bottom Increasing, erratic
No change
Drag decreases when pumping
No change
Drag decreases when pumping
RIG TEAM INDICATIONS SHAKER TRENDS
Blocky or angular rock fragments
LOGGER TRENDS
Same as shaker shaker trends. Possible offset offset well data clues. clues. Prognosed fractured formation
MUD TRENDS
No change
PREVENTIVE ACTION NOTE: With fractured formations, formations, maintaining a good quality filter filter cake can help to support the formation formation in some cases. Generally, 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:
Circulate the hole clean before drilling ahead 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 Anticipate reaming reaming during trips. Ream fractured zone zone cautiously Be prepared for the potential of lost circulation when drilling fractured formations Problem likely to stabilize with time
Page 39
STUCK PIPE
HOLE PROBLEMS
HOLE PACK-OFF / BRIDGE
CEMENT BLOCKS CAUSE:
CEMENT BECOMES UNSTABLE AROUND CASING SHOE, OPEN HOLE SQUEEZE PLUG OR KICK-OFF PLUG HARD CEMENT CHUNKS FALL INTO THE WELLBORE AND JAMS THE DRILL STRING
WARNING:
! ! L L U P R E V O
EXCESSIVE CASING RATHOLE CEMENT SQUEEZE JOB CEMENT KICK-OFF PLUG CEMENT CAVINGS AT SHAKER AND/OR IN MUD LOGGER SAMPLES
INDICATIONS:
PROBLEM CAN OCCUR ANYTIME SUDDEN, ERRATIC TORQUE AND DRAG JUST BEFORE STICKING
CASING RAT HOLE
CIRCULATION POSSIBLE
FIRST ACTION:
ATTEMPT ATTEMPT TO TO BREAK CHUNKS CHUNKS WITH JARRING & TORQUE JAR IN THE OPPOSITE DIRECTION OF STRING MOVEMENT PRIOR TO STICKING
SQUEEZE PLUG
APPLY APPLY JARRING FORCE FORCE & TORQUE TORQUE GRADUALLY CIRCULATE HIGH DENSITY, HIGH VISCOSITY SWEEPS
B R RI I D D G GE D D ! !! !
! ! K U C T S
PREVENTIVE ACTION:
MINIMIZE CASING RATHOLE ALLOW SUFFICIENT SUFFICIENT CURING TIME REAM CASING SHOE AND OPEN HOLE PLUGS THOROUGHLY BEFORE DRILLING AHEAD SLOW TRIP SPEED BEFORE BHA ENTERS CASING SHOE OR PLUG DEPTH
Page 40
STUCK PIPE
HOLE PACK-OFF / BRIDGE
HOLE PROBLEMS
SOFT CEMENT CAUSE:
CIRCULATION IS ATTEMPTED WITH THE BOTTOM OF THE DRILL STRING IN SOFT CEMENT
! ! N W O D T E S
PUMP PRESSURE CAUSES THE CEMENT TO FLASH SET HIGH PENETRATION RATE WHEN CLEANING OUT SOFT CEMENT
SOFT CEMENT
WARNING:
TRIPPING IN HOLE AFTER SETTING AN OPEN HOLE CEMENT PLUG OR AFTER A CEMENT JOB SET DOWN WEIGHT OCCURS ABOVE THE THEORETICAL TOP OF CEMENT
INDICATIONS:
OCCURS AS PUMP PRESSURE IS APPLIED CIRCULATION HIGHLY RESTRICTED OR IMPOSSIBLE
FL ASH SET!!
PUMP
FIRST ACTION:
BLEED TRAPPED PUMP PRESSURE
PRESSURE
JAR UP WITH MAXIMUM TRIP LOAD
PREVENTIVE ACTION:
KNOW CEMENT SET TIME IF SET DOWN WEIGHT IS OBSERVED WHILE RIH, PULL 2 STANDS BEFORE BEFORE CIRCULATING CIRCULATING START CIRCULATING 2 STANDS ABOVE TOP OF CEMENT
! ! L L U P R E V O
CONTROL DRILL WHEN CLEANING OUT CEMENT
! C K ! S T U FIRM CEMENT
Page 41
STUCK PIPE
HOLE PROBLEMS
HOLE PACK-OFF / BRIDGE
JUNK
CAUSE:
POOR HOUSE KEEPING ON THE FLOOR, HOLE COVER NOT INSTALLED DOWN HOLE EQUIPMENT FAILURE FAILURE JUNK FALLS INTO WELLBORE AND JAMS THE DRILL STRING 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 SUDDEN AND ERRATIC TORQUE AND DRAG LIKELY JUST BEFORE STRICKING
! ! L L U P R E V O
MISSING FLOOR TOOL OR EQUIPMENT CIRCULATION UNRESTRICTED, DEPENDING ON TYPE OF JUNK
FIRST ACTION:
IF MOVING UP WHEN STICKING OCCURRED, JAR DOWN WITH MAXIMUM TRIP LOAD APPLY APPLY TORQUE IF IF PROGRESS IS IS MADE IF MOVING DOWN, JAR UP WITH MAXIMUM TRIP LOAD, DO NOT APPLY TORQUE
! ! K U C S T
PREVENTIVE ACTION:
GOOD HOUSE KEEPING ON FLOOR INSPECT HANDLING EQUIPMENT KEEP HOLE COVERED
HARD FORMATION
INSPECT DOWN HOLE EQUIPMENT
Page 42
STUCK PIPE
HOLE PACK-OFF / BRIDGE
HOLE PROBLEMS CEMENT BLOCKS
PREVENTIVE ACTION Limit casing rathole to minimize a source of cement blocks Several squeeze jobs at the casing shoe increases the potential for cement blocks Allow sufficient sufficient cement cement curing time before drilling out 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 Verify cement compressive strength with cement company before drilling out Control drill when cleaning out soft cement JUNK
PREVENTIVE ACTION Inspect slip and tong dies regularly Use good house keeping practices on the rig floor Install drill string wiper rubber as quickly as possible Keep hole covered when out of the hole Maintain rig floor equipment in good operating condition
Page 43
STUCK PIPE
HOLE PROBLEMS
DIFFERENTIAL STICKING
DIFFERENTIAL STICKING A sticking force developed when differential differential pressure (overbalance) (overbalance) forces a stationary drill string into the the thick filter cake of a permeable zone
. PERMEABLE FORMATION . Sandstone / fractured limestone
OVER BALANCE . Wellbore pressure greater than formation pressure
STRING CONTACTS FILTER CAKE . Angled wellbore / unstabilized BHA increases potential
SANDSTONE 4000 PSI NO FIL FILTER TER CAKE
FILTER CAKE
HYDROSTATIC PRESSURE (HSP) 5000 PSI
HIGH
CONTROLLED FLUID LOSS
FLUID LOSS
STATIC FILTER CAKE
DYNAMIC FILTER FILTER CAKE
HSP 500 000 0 .
STRING MOTION STOPPED
HSP IS BLOCKED
PSI
1" LOW PRESSURE AREA DEVELOPS DEVELOPS BEHIND PIPE
. No string motion or circulation develops static cake
LOW PRESSURE AREA . An area of low pressure develops between the pipe & filter cake . Overbalance pressure across the contact area determines the differential force
HSP 5000 PSI
4"
FP 4000 PSI
LOW PRESSURE AREA
Page 44
STUCK PIPE
DIFFERENTIAL STICKING
DIFFERENTIAL STICKING
TOP VIEW
STATIC FILTER CAKE
FORMATION PRESSURE 4000 psi
4"
HSP 5000 PSI
LOW PRESSURE AREA
! ! L L U P R E V O
SIDE VIEW 4"
1200 Sq In Contact Area
S T U C K ! ! ! SAND 4000 PSI
DIFFERENTIAL FORCE 1,200,000 LBS
25'
(300")
Page 45
HOLE PROBLEMS
STUCK PIPE
HOLE PROBLEMS
DRILLER TRENDS DRILLING CONNECTION
DRAG Possible increase
INDICATIONS INDICATIONS OF DIFFERENTIAL STICKING TORQUE PRESSURE No change
Increasing overpull off slips
TRIPPING IN
Increasing overpull off slips
BACK REAMING
Increasing overpull off slips
PUMPING OUT
Increasing overpull off slips
OTHER
No change No change
Increasing overpull off slips
TRIPPING OUT
DIFFERENTIAL STICKING
No change
No change
No change
RIG TEAM INDICATIONS SHAKER TRENDS
No change
LOGGER TRENDS
High overbalance. Permeable formation depth. Permeability Permeability data to estimate stricking potential
MUD TRENDS
Increasing mud weight. Increasing plastic viscosity viscosity and low gravity gravity solids. High API water loss, thick thick filter cake
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 Maintain fluid loss within specifications Minimize BHA length when possible Limit the length of unstabilized unstabilized BHA. Use spiral drill collars drilling and tripping connections while BHA BHA is opposite KEEP THE STRING MOVING . Consider rotating the string during drilling 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 minimize seepage loss with plugging agents Keep a pipe releasing pill ready at the well site when differential stricking potential is high
Page 46
STUCK PIPE
WELLBORE GEOMETRY
HOLE PROBLEMS
WELLBORE GEOMETRY Hole diameter and/or angle relative to BHA geometry and/or stiffness will not allow passage of the drill string
DIRECTION / ANGLE CHANGE / HOLE ID DECREASE
BHA CHANGE STIFF ASSEMBLY
MICRO DOGLEGS
KEY SEAT MOBILE FORMATION
LEDGES UNDER GAUGE HOLE BHA CHANGE
STIFF ASSEMBLY
POOH WITH LIMBER BHA
STUCK!!
S E T D O W N ! !
RIH WITH STIFF BHA S T TU C C K ! ! !
Page 47
STUCK PIPE
HOLE PROBLEMS
WELLBORE GEOMETRY DIRECTION / ANGLE CHANGE
KEY SEAT N O I S N E T
TOOLJOINT OD
R O
T A N T I I O
SIDE LOAD
W E I G H T
SLOT WORN INTO FORMATION
! ! L L U P R E V O
! K ! C U S T
BHA
O
Page 48
WELLBORE GEOMETRY DIRECTION / ANGLE CHANGE
STUCK PIPE MICRO DOGLEGS
! ! L L U P R E V O
! ! ! K U C T S
A G R D
D R R A G
! ! ! K U C T S
Page 49
HOLE PROBLEMS
STUCK PIPE
HOLE PROBLEMS
LEDGES SOFT FORMATION
! ! L L U P R E V O
A G R D HARD FORMATION
S T U C K ! !
A G R D
S T TU C U CK ! K ! ! !
A G R D
Page 50
WELLBORE GEOMETRY DIRECTION / ANGLE CHANGE
WELLBORE GEOMETRY HOLE DIAMETER DECREASE
STUC ST UCK K PI PIPE PE
MOBILE FORMATION
N O I T T H A G I M E R O W F
PLASTIC SALT OR SHALE
SQUEEZING FORCE
S T U C K ! ! !
N O I T T H A G I M E R O W F
! ! L L U P R E V O
SQUEEZING FORCE
K ! ! ! C S T U
Page 51
HOLE PROBLEMS
STUCK STU CK PI PIPE PE
HOLE PROBLEMS
UNDERGAUGE HOLE
ABRASIVE SANDSTONE
N ! ! T W H O G D I T E E W S
S T U C K ! ! !
Page 52
WELLBORE GEOMETRY HOLE DIAMETER DECREASE
STUCK STU CK PI PIPE PE
WELLBORE GEOMETRY
HOLE PROBLEMS
The The indi indica cati tion ons s of Well Wellbo bore re Geom Geomet etry ry prob proble lems ms are are obse observ rved ed only only when when BHA is movin in the the hole hole sect sectio ion n with with the the geometry problem.
DRILLER TRENDS DRILLING CONNECTION TRIPPING OUT
TRIPPING IN
INDICATIONS INDICATIONS OF WELLBORE GEOMETRY PROBLEMS TORQUE OTHER PRESSURE DRAG Increasing, erratic
Increasing, erratic
Increasing, erratic
No change
Momentary over pull & set down
Surge to start circulation
Momentary over pull & set down
Increasing, erratic overpull with BHA at problem zone Increasing, erratic set down weight
BACK REAMING
Erratic
PUMPING OUT
Increasing, erratic overpull
Momentary over pull & set down Begins at depth of problem formation Increasing, erratic
No change
Momentary over pull
No change
Momentary over pull
RIG TEAM INDICATIONS SHAKER TRENDS
No change
LOGGER TRENDS MUD TRENDS
No change No change
PREVENTIVE ACTION Optimize BHA design (run only what is required) and when possible, minimize BHA stiffness 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 severity to 3 /100' or less. Minimize rotating hours below 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 Minimize sharp, frequent wellbore course changes Avoid prolonged circulation in suspected suspected micro dogleg dogleg section to prevent hole wash out and forming ledges With mobile salts consider using a slightly under saturated mud system system to allow a controlled washout. If necessary, 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 STU CK PI PIPE PE
WELLBORE GEOMETRY
HOLE PROBLEMS
The The indi indica cati tion ons s of Well Wellbo bore re Geom Geomet etry ry prob proble lems ms are are obse observ rved ed only only when when BHA is movin in the the hole hole sect sectio ion n with with the the geometry problem.
DRILLER TRENDS DRILLING CONNECTION TRIPPING OUT
TRIPPING IN
INDICATIONS INDICATIONS OF WELLBORE GEOMETRY PROBLEMS TORQUE OTHER PRESSURE DRAG Increasing, erratic
Increasing, erratic
Increasing, erratic
No change
Momentary over pull & set down
Surge to start circulation
Momentary over pull & set down
Increasing, erratic overpull with BHA at problem zone Increasing, erratic set down weight
BACK REAMING
Erratic
PUMPING OUT
Increasing, erratic overpull
Momentary over pull & set down Begins at depth of problem formation Increasing, erratic
No change
Momentary over pull
No change
Momentary over pull
RIG TEAM INDICATIONS SHAKER TRENDS
No change
LOGGER TRENDS MUD TRENDS
No change No change
PREVENTIVE ACTION Optimize BHA design (run only what is required) and when possible, minimize BHA stiffness 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 severity to 3 /100' or less. Minimize rotating hours below 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 Minimize sharp, frequent wellbore course changes Avoid prolonged circulation in suspected suspected micro dogleg dogleg section to prevent hole wash out and forming ledges With mobile salts consider using a slightly under saturated mud system system to allow a controlled washout. If necessary, 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 CIRCULA CIRC ULATION TION
LOST CIRCULA C IRCULATION TION
HOLE PROBLEMS
Measurable loss of whole mud (liquid phase and solid phase) to the formation. Lost circulation can occur at any depth during any operation
ADVERSE EFFECTS ON DRILLING OPERATIONS OPERATIONS SURFACE HOLE INTERMEDIATE HOLE PRODUCTION HOLE Loss of drive /conductor shoe . Hole cleaning problems . Hole bridge /collapse . Stuck pipe . Well control event . Loss of well
Loss of fluid level monitoring . Loss of formation evaluation . Hole cleaning problems . Hole bridge /collapse . Extended wellbore exposure time . Stuck pipe . Well control event . Under ground blowout . Additional casing string
Loss of fluid level monitoring . Loss of formation evaluation . Hole cleaning problems .. Hole bridge /collapse . Extended wellbore exposure time . Stuck pipe . Well control event .. Underground blowout .. Additional casing string . Production zone damage
LOST CIRCULATION MECHANISMS PRESSURE INDUCED FRACTURE NATURALLY EXISTING FRACTURES / HIGH PERMEABILITY
Wellbore pressure exceeds fracture pressure of the formation causing the rock to ra open (fracture)
Over balanced wellbore pressure is exposed to a formation with unsealed fractures or high permeability
CAUSES OF LOST LO ST CIRCULATION PRESSURE INDUCED FRACTURES Excessive mud weight Annulus friction pressure
NATURAL NATURAL FRACTURES / PERMEABILITY Unconsolidated formation Fissures / fractures
Wellbore pressure surges
Unsealed fault boundary
Imposed / trapped pressure
Vugular / cavernous formation
Shut-in pressure Low formation pressure
Page 55
HOLE PROBLEMS
LOST CIRCULATION PRESSURE INDUCED FRACTURES
CASING SHOE
FIRST INTERFACE
LOW PRESS SAND
Page 56
MECHANISMS
MECHANISMS
LOST CIRCULA CIRC ULATION TION NATURAL FRACTURES / HIGH PERMEABILITY
UNCONSOLIDATED
VUGULAR
CAVERNOUS
U N S E A L E D F A U L T
FRACTURED FORMATION
Page 57
HOLE PROBLEMS
LOST CIRCULATION
HOLE PROBLEMS
MECHANISMS
LOSS SEVERITY CLASSIFICATIONS CLASSIFICATIONS
SEEPAGE LOSS (< 20 BBLS/HR)
PARTIAL LOSS (> 20 BBLS/HR)
TOTAL LOSS (NO RETURNS)
IMMEDIATE DROP IN FLUID LEVEL WHEN PUMPING IS STOPPED
GRADUAL LOSSES OPERATION NOT INTERRUPTED
RETURN FLOW STOPS IMMEDIATELY PUMP PRESSURE DECREASE
SLOW TO TO REGAIN REGAIN RETURNS AFTER STARTING STARTING CIRCULATION
POSSIBLE WARNING OF INCREASED LOSS SEVERITY
STRING WEIGHT INCREASE
OPERATIONS USUALLY INTERRUPTED
OPERATION SUSPENDED REMEDIAL ACTION REQUIRED
REMEDIAL ACTION REQUIRED
METHODS FOR LOCATING LOSS DEPTH Successful treatment of lost circulation depends greatly on locating the depth of the loss zone
SURVEY METHODS
PRACTICAL METHODS OFFSET WELL W ELL DATA
TEMPERATURE SURVEY
GEOLOGIST / LOGGER IDENTIFIES POTENTIAL LOSS ZONE
ACOUSTIC LOG RADIOACTIVE TRACER
MONITORING FLUID LEVEL TRENDS WHILE DRILLING
SPINNER SURVEY PRESSURE TRANSDUCER HOT WIRE SURVEY
CONSIDERATIONS CONSIDERATIONS FOR SURVEY METHODS SURVEY TOOLS NOT ALWAYS AVAILABLE CONSIDERABLE TIME REQUIRED TO RUN SURVEY SURVEYS REQUIRE LARGE VOLUME OF MUD RESULTS OFTEN DIFFICULT TO INTERPRET POSSIBILITY OF LOSING SURVEY TOOL IN THE HOLE
Page 58
RESTORING CIRCULATION CIRCULATION
LOST CIRCULA CIRC ULATION TION
HOLE PROBLEMS SOLUTION GUIDELINES
GUIDELINES FOR LOST CIRCULATION SOLUTIONS ACTION MINIMIZE MUD WT
FORMATION "HEALING TIME"
LOSS CIRC MATERIAL (LCM)
SPECIALTY TECHNIQUES
CEMENT
DRILLING BLIND
RESULTS
CONSIDERATIONS
Reduced wellbore pressure (the driving force pushing mud into the loss zone
More successful with pressure induced fractures . Possible well control event or hole instability problems
Reactive clays of loss zone swell with water of WBM producing a plugging effect . Soft shales deform with formation stress helping to "heal" the fracture
More successful with fresh water mud lost to shale formations . Better results with LCM . Normal 6 - 8 hours wait time with string in casing
Effectively bridges, mats and seals small to medium fractures / permeability
Less effective with large fractures, faults . Ineffective with cavernous zones . Increase LCM lbs/bbl with loss severity
A plug base is pumped into the the loss zone followed by a chemical activator The two materials form a soft plug
Can be used in production zones . Increased risk of plugging equipment . Plug breaks down with time
Cement slurry is squeezed into the loss zone under injection pressure . The slurry cures to a solid plug
Provides a "fit-to-form" solid plug at or near the stress of the surrounding formation .
In some cases, the only practical solution is to drill without returns
Not a consideration where well control potential exist . Set casing in the first compentent formation
GUIDELINES FOR SUCCESSFUL LCM RESULTS RESULTS
Page 59
HOLE PROBLEMS
RESTORING CIRCULATION
LOST CIRCULATION LOSS CIRCULATION MATERIAL (LCM)
MATERIAL
DEFINITION
GRADES
FIBROUS & FLAKED GRANULAR
LCM BLEND
CELLULOSTIC CALCIUM CARBONATE
SIZED SALT
SEEPAGE SEEPAGE LOSS SOLUTIONS (< 20 BBLS/HR) FIRST ACTION Reduce ROP to limit cuttings load Minimize mud rheology Minimize GPM Minimize wellbore pressure surges Minimize mud wt Consider pulling into casing and waiting 6 to 8 hours
RECOVERY Add LCM LCM pill in 5 - 10 10 PPB increments. increments. Evaluate Evaluate results results over over 2 circulations before increasing to next level of LCM concentration. Mix in 30 to 50 bbl batches dictated by hole size. Consider spotting LCM pill before POOH
NON-PRODUCTIVE INTERVALS WBM: . LCM LCM Blen Blend d (F) 5 - 15 PPB PPB LCM Blend Blend (M) 5 - 15 PPB Flake Flaked d (F/M) (F/M) 10 - 20 PPB PPB
OBM / SBM: . Cellulosi Cellulosic c (F/M) (F/M) 2 -25 -25 PPB
PRODUCTION ZONE EXPOSED WBM: . Limestone Limestone (F/M) (F/M) 5 - 30 PPB
OBM / SBM: . Cellulosic (F/M) 2 - 25 25 PPB Limestone (F/M) 5 - 15 PPB
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 CIRCULATION
LOST CIRCULA CIRC ULATION TION
HOLE PROBLEMS
PARTIAL LOSS SOLUTIONS (> 20 BBLS/HR) FIRST ACTION Reduce ROP to limit cuttings load
RECOVERY Add LCM pill in 5 -10 PPB increments. Evaluate results over 2 circulations before increasing increasing to next level of LCM concentration. Mix in 30 to 50 bbl batches dictated by hole size. Consider spotting LCM pill before POOH
Minimize mud rheology Reduce GPM Minimize wellbore pressure surges
NON-PRODUCTIVE INTERVALS WBM: . LCM Blend (M) 15 - 25 PPB LCM Blend Blend (C) 15 - . 25 PPB Walnu Walnutt (M/C) (M/C) 10 - 20 20 PPB
PRODUCTION ZONE EXPOSED
Minimize mud wt Consider pulling into casing and waiting 6 to 8 hours
OBM / SBM: . Cellulos Cellulosic ic (F/M) 10 -25 PPB Cell Cellul ulos osic ic (C) (C) .10 -25 -25 PPB PPB Walnut (M) . 5 -15 PPB
WBM: . LCM Blend Blend (F) 5 - 15 15 PPB LCM Blend (M) 5 - 15 PPB PPB Cellulo Cellulosic sic (M) . 5 - 15 PPB
OBM / SBM: . Cellul Cellulosi osic c (F/M) (F/M) 2 - 25 PPB Lime Limest ston one e (F) (F) .. 5 - 15 PPB PPB
TOTAL LOSS SOLUTIONS FIRST ACTION Pull off bottom, keep
RECOVERY Formulations for the specialty pill and cement are dictated by conditions of each event
string moving
NON-PRODUCTIVE INTERVALS Fill annulus with water or light mud
Record strokes if /
OBM / SBM: . 30 - 40 PPB LCM Pill Specialty Pill Cement Squeeze
WBM: . 40 PPB LCM Pill Specialty Pill Cement Squeeze
when annulus fills up
Consider pulling into the casing
Minimize wellbore pressure surges
PRODUCTION ZONE EXPOSED WBM: . 40 PPB LCM Pill Specialty Pill Cement Squeeze
OBM / SBM: . 30 - 40 PPB LCM Pill Specialty Pill Cement Squeeze
ADDRESS ADDRESS RESERVO RESERVOIR IR NEEDS
ADDRESS ADDRESS RESERV RESERVOIR OIR NEEDS
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
LOST CIRCULATION
HOLE PROBLEMS
SEALING MATERIALS USED FOR LOST CIRCULATION Concentration Largest Fracture Type D e s c ri p t i o n L b s /b bl Sealed (inches)
M a terial
0 Nutshell
Granular
50% - 3/16+ 10 mesh 50% - 10+ 100 mesh
Plastic
Granular .
50% - 3/16+ 10 mesh 50% - 10+ 100 mesh
20
Limestone .
Granular
..50% - 3/16+ 10 mesh 50% - 10+ 100 mesh
40
Sulphur
Granular
. 50% - 3/16+ 10 mesh 50% - 10+ 100 mesh
120
Nutshell
Granular
50% - 10+ 16 16 mesh 50% - 30+ 100 mesh
E panded Percite
Granular
50% - 3/16+ 10 mesh .. 50% - 10+ 100 mesh
Cellophane
Laminated
3/4" flakes
.
8
Sawdust
Fibrous
.. 1/4" particles
.
10
Prairie Hay .
Fibrous
.1/2" particles
.
10
Bark
Fibrous
3/8" particles
Cottonseed. Hulls
Granular
Fine
Prairie Hay
Fibrous
Cellophane
Laminated
.
.
20
60
10
.
. 3/8" particles
.
20
10
12
1/ 1/2" flakes
.
8
.
Shredded Wood Sawdust
.
Fibrous
1/4" fibers
Fibrous
1/16" particles
8
20
Page 62
.4
.8
.12
.16
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RESTORING CIRCULATION CIRCULATION
LOST CIRCULA CIRC ULATION TION
HOLE PROBLEMS
SPOTTING PROCEDURES FOR LOST CIRCULATION MATERIAL (LCM) Locate the loss zone . Mix 50 - 100 barrels of mud with 25 - 30 ppb bentonite and 30 - 40 ppb LCM . Position the drill string +/-100 feet above the loss zone . If open-ended, pump 1/2 of the pill into the loss loss zone. Stop the pump, wait 15 minutes and pump the remainder of the pill . If pumping through the bit, pump the entire pill and follow with 25 barrels of mud . If returns are not regained, repeat procedure. If returns are not regained, wait 2 hours and repeat procedure . If returns are not regained after pumping 3 pills, consider other options to regain circulation
SPOTTING PROCEDURES FOR SPECIALTY PILL
SPOTTING PROCEDURES FOR GUNK PILL
Page 63
HOLE PROBLEMS
LOST CIRCULATION
PREVENTION
SPOTTING PROCEDURE FOR CEMENT The cement slurry formulation should be tested by the cement company to determine the thickening time
If possible, drill through the entire loss circulation interval 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 Mix and pump 50 to 100 bbls of cement slurry Follow the slurry with a sufficient volume of mud or water to balance the U-Tube Wait 6 to 8 hours and attempt to fill the annulus Repeat the procedure if returns are not regained It may be necessary to drill out the cement before repeating the procedure
LOST CIRCULATION PREVENTION GUIDELINES Prevention of lost circulation must be considered in the well planning, drilling and post analysis phases Design the casing program to case-off low pressure or suspected lot circulation zones Maintain mud weight to the minimum minimum required to control known formation 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 Start circulation slowly after connections and periods of non-circulation 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 Reduce pipe tripping speeds to minimize swab/surge pressure Plan to break circulation at 2 to 3 depths while tripping in the hole Minimize annular restrictions 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. Be prepared for mud losses due to shaker screen plugging
Page 64
LOST CIRCULA CIRC ULATION TION
HOLE PROBLEMS DRILLING BLIND
PRECAUTIONS WHILE DRILLING WITHOUT RETURNS
Circumstances may dictate 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 have Drilling Manager approval
Page 65
RIG REPAIR
UNSCHEDULED RIG REPAIR
An interruption in planned planned operations caused by a breakdown in the the drilling rig equipment. equipment. Running rig equipment to failure is not cost effective for the Contractor, Operator or wellbore
IMPACT OF UNSCHEDULED RIG REPAIR OPERATOR DRILLING CONTRACTOR WELLBORE FINANCIAL PENALTIES
HIGH RISK OF OTHER UNSCHEDULED EVENTS
COST OF EMERGENCY REPAIR
OPERATOR INCREASED WELL COST DELAYED PRODUCTION
EXTENDED EXPOSURE TIME POSSIBLE PERSONNEL INJURY
LOSS OF PRODUCTION LOSS OF HOLE SECTION
EXTENSIVE EQUIPMENT DAMAGE LOSS OF WELL LOSS OF FUTURE CONTRACTS
PRIMARY CONTRACTOR AND OPERATOR OBJECTIVES CONTRACTOR OPERATOR NO PERSONNEL INJURY
NO PERSONNEL INJURY
NO WELL CONTROL INCIDENT
NO WELL CONTROL INCIDENT
OPTIMIZE EQUIPMENT LIFE
OPTIMIZE DRILLING OPERATION
MINIMIZE RIG REPAIR
MINIMIZE UNSCHEDULED EVENTS
CONTROL EQUIPMENT COST
CONTROL FINAL WELL COST
LONG TERM DRILLING CONTRACT
COST EFFECTIVE PERFORMANCE
PREVENTIVE MAINTENANCE PROGRAM (PMP)
A program designed to schedule schedule regular inspection, maintenance and/or and/or repair of drilling equipment prior to failure The historical life expectancy of rig equipment is based on the frequency of maintenance
FOUR COMPONENTS OF A PREVENTIVE MAINTENANCE PROGRAM CLOSED LOOP
CREW FEED BACK
RECORD KEEPING
AUDITING
Equipment history
Through inspections
Rig to management
Equipment trends
Well designed checklists
Roles defined
Equipment maintenance
Management to rig
Refining and tailoring the system
Follow-up plans/ reports
Clear guidelines
Page 66
RIG REPAIR
COMPREHENSIVE PMP EQUIPMENT LIST MAIN ENGINES
HIGH PRESSURE MANIFOLDS / VALVES / HOSES
GENERATORS / SCR SYSTEMS
HYDRAULIC OPERATING SYSTEMS
MOORING / STATION KEEPING SYSTEM
COMPRESSED AIR SYSTEM
BALLAST AND BILGE SYSTEM
CRANES
TENSIONING EQUIPMENT
PIPE HANDLING SYSTEM
BOPE / CONTROL SYSTEM
CIRCULATING SYSTEM
RISER / DIVERTER SYSTEM
MUD PUMPS
HOISTING EQUIPMENT
BULK MIXING SYSTEM
TOP DRIVE SYSTEM
SOLIDS CONTROL SYSTEM
ROTARY SYSTEM
RIG COMPUTER SYSTEMS
PMP FREQUENCY SCHEDULE HOURLY
BI-MONTHLY
EVERY TWO YEARS
DAILY
QUARTERLY
EVERY THREE YEARS
WEEKLY
EVERY FOUR MONTHS
EVERY FOUR YEARS
BI-WEEKLY
SEMI-ANNUALLY
EVERY FIVE YEARS
MONTHLY
ANNUALLY ANNUALLY
EVERY EIGHT YEARS
BENEFITS OF A SUCCESSFUL PREVENTIVE MAINTENANCE PROGRAM Ensure equipment life expectancy Reduce down time for unscheduled rig repair Lower well cost Reduce severity of damage to equipment Maintenance is less costly than emergency repair Less chance of personnel injury. Increase contractor profit margin 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 Opportunity for contractor input / involvement during well planning
EVALUATE EVALUATE RIG REPAIR FAILURE SEVERITY WHO SHOULD BE NOTIFIED
.
ARE PERSONNEL OR THE RIG IN DANGER
WHAT IMMEDIATE ACTION IS REQUIRED
IS THE WELLBORE IN DANGER
CAN NORMAL OPERATIONS CONTINUE
WHAT SAFETY PRECAUTIONS ARE REQUIRED
CAN PARTIAL OPERATIONS CONTINUE
CAN THE FAILURE BE REPAIRED ON SITE
IS OPERATIONAL SHUT DOWN REQUIRED
PREVENTATIVE ACTION PLAN
Page 67
RIG REPAIR INTEGRATE RIG MAINTENANCE WITH THE WELL PLAN Schedule rig maintenance during low risk operations. This may require early maintenance or risking postponed maintenance. PMP scheduling design should consider the potential for unscheduled events
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RIG REPAIR DRILLING SYSTEM BREAK DOWN EMERGENCY PROCEDURES If rig equipment failure shuts down a major drilling system, immediate action must be taken to protect the personnel, rig and wellbore from associated events
DRILLING SYSTEM BREAK DOWN STATION STATION KEEPING KEE PING
INITIAL RESULT Rig drifts or drives off location
SECONDARY RESULT Stuck pipe
Stop rotation and circulation
BOP / riser damage
Position tooljoint above the hang-off ram . Close hang-off rams and slack-off to predetermined weight
Drill string is sheared-off Drill string damage Upper marine riser connector unlatches
TOTAL RIG POWER
Loss of station keeping Loss of hoisting, rotation, circulation
ACTION PLAN
Surface equipment failure / damage Rig drift-off damage . Stuck pipe . Well control Surface equipment failure / damage
Initiate drilling contractor's emergency procedures Start emergency generator Initiate preliminary disconnect procedure Raise drill string off bottom with motion compensator Circulate with cementing pump Monitor well for flow
TOTAL DRILLING POWER
Possible loss of station keeping . Loss of hoisting, rotation, circulation
Possible rig drift - off damage
Start emergency generator Initiate preliminary disconnect procedure
Stuck pipe Circulate with cementing pump Well control If possible, rotate drill string with power tongs Monitor well for flow
TOP DRIVE SYSTEM (TDS)
Possible loss of rotation, hoisting, circulation
Stuck pipe
If possible, trip to to casing shoe for for repair
Well control
If not possible, set slips, tie slip handles and rotate pipe in slips If possible, rig-up to circulate Monitor well for flow
HOISTING SYSTEM
Cannot raise the drill string
Stuck pipe
Continue circulation / rotation Reciprocate drill string with motion compensator
ROTATING SYSTEM
Cannot rotate the drill string
Stuck pipe
Reciprocate drill string Trip to casing shoe for repair If possible, rotate drill string with power tongs Maintain full circulation
CIRCULATING SYSTEM
WELL CONTROL SYSTEM
Cannot circulate the wellbore
Cannot shut-in during kick
Stuck pipe
Trip to casing shoe for repair
Well control
Rotate / reciprocate reciprocate the drill string if repair is made while in open hole
Personnel injury
Non emergency - secure the well to make repairs
Equipment damage Emergency - Initiate evacuation procedures
Blowout Loss of well Environmental damage
Page 69
DOWN HOLE EQUIPMENT FAILURE DOWN HOLE EQUIPMENT FAILURE
An interruption in planned operations caused caused by drilling /evaluation /evaluation tool failures failures other than drill string failures. Down hole tool selection and operation operation is critical in the reduction reduction of tool failure
DOWN HOLE EQUIPMENT CYCLE Drilling engineer specifies equipment Drilling foreman orders equipment Toolpusher inspects/checks equipment Driller picks up/runs equipment Rig team post analyzes equipment
HIGH FAILURE RATE DOWNHOLE TOOLS
DOWN HOLE TOOL
FAILURE
ROLLER CONE BITS . DOWN HOLE MOTOR . SHOCK SUB . DRILLING JAR . MWD / LWD . LOGGING
Lost cones (most common fishing job) . Motor stops drilling . Seal washout . Untrained personnel . Dump valve, software, LCM plugging . Last-minute changes, inexperienced operators, no maintenance
SURVEY EQUIPMENT
Film, batteries, wireline failure, insufficient bar weight
SPECIALTY EQUIPMENT
Untrained personnel, unproven technology
PACKER / DST TOOLS
Leaks, packer does not release, incompatible with other tools, high angle holes
CAUSE OF TOOL FAILURE
CAUSE METAL FATIGUE . IMPROPER TOOL SELECTION
NOTE
Cyclic stress reversals . Loads exceed design limits, incompatible with other tools
. IMPROPER TOOL OPERATION
Untrained personnel, inattention
. EXCEEDED DESIGN LIMITS . EXCEEDED DESIGN LIFE . TRANSPORTATION TRANSPORTATION /
Accidental Accidental /intentional /intentional overload overload Economic based, untrained personnel . Untrained personnel
HANDLING DAMAGE . HOSTILE ENVIRONMENT DESIGN / MANUFACTURING
H2S, CO2, high temperature, corrosive mud, high angle, hard abrasive formations Quality control failed
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
FACTORS THAT INFLUENCE THE TOOL SELECTION PROCESS FACTOR
INQUIRIES WELLBORE CONDITIONS
DOWN HOLE ENVIRONMENT
TOOL PHYSICAL PROPERTIES
COMPATIBILITY
OPERATIONS
Temperature limitations of tools H2S, CO 2, Corrosion resistance Oil resistant rubber goods Hydrostatic pressure limitations Hole angle limitations Hole size versus tool size DIMENSIONS Length, OD, ID of tool Weight and grade Connection type Special make up torque requirements, thread dope Stress relief features Connections compatible with other down hole equipment Will tool work with other equipment OPERATING PARAMETERS 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 required/provided Operating manual provided Safety recommendations Settings / calibration data Maintenance requirements FISHING TOOL METHODS
FISHING Tool dimensions diagram provided Required fishing tools / ease of fishing Fishing records available Tool lost-in-hole consequences
SUPPORT
QUALITY CONTROL
COST
LIMITATIONS
Back up tools readily available / delivery time Are spare parts needed needed / readily available Transportation Transportation problems / hazardous cargo Air transportable Required deck space / deck load RELIABILITY OF TOOL New or rebuilt tool Hours since last rebuilt / inspection records Performance record of tool on offset wells Performance record of tool worldwide Operating/standby Operating/standby rental rates / repair agreements Lost-in-hole charges / insurance Success/failed performance rate Depth / external pressure limitation Yield strength Drilling fluid - Oil, LCM, Hematite Battery packs
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
RIG-SITE TOOL INSPECTION CHECK LIST
ITEM
C HE C K P O I N T S
PAPER WORK
PHYSICAL CONDITION
COMPATIBILITY
OPERATION
TOPICS
TOOL FAILURE PREVENTION RECOMMENDATION
UNFAMILIAR /NEW TECHNOLOGY TOOL OPERATING MANUAL AWARENESS AWARENESS / REFRESHERS . TOOL FAILURE REPORT
SERVICE / EQUIPMENT
Page 72
DRILL STRING FAILURE MINIMUM YIELD STRENGTH (MYS)
PLANNING
The minimum load (lbs/sq in of metal) at which plastic deformation of the metal begins Accumulated metal metal damage caused caused by stress reversals
METAL FATIGUE
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
DRILL PIPE FAILURE PREVENTION PLANNING C O M P O N EN T
D E F IN I T I O N
EXAMPLE
ATTRIBUTES ATTRIBUTES
The dimensions and mechanical properties built into the drill string components. Attributes determine the the loads that can be applied
Wall thickness, Yield strength, Toughness, Toughness, Upset geometry
DESIGN
The designed strength of the drill sting must exceed the loads required to drill the well. well. Operating below the design design limits extends the life of the drill string
Anticipate Anticipated d loads, loads, Correct Correct selectio selection n and positioning of string components, Posting maximum tension and torsion limits for the Driller
INSPECTION
OPERATIONS
SURROUNDINGS
Examine the drill string components to ensure it meets minimum Onsite visual inspection, Electronic inspection based on drill string and drilling specifications. specifications. Inspections detect detect wear before it results in a conditions down hole failure Improper use, handling and storage of the drill string results in premature string failure
Correct connection make-up Calibrating gauges, Operational use and handling practices
The chemical and mechanical environment in which the drill string is operated. If the surroundings become hostile, hostile, the inspection frequency should be increased to minimize failures
Doglegs, Buckling, Vibrations, Corrosion, High angle wells
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
DRILL STRING FAILURE CAUSES
BELOW MINIMUM YIELD STRENGTH
ABOVE MINIMUM YIELD STRENGTH
85%OF TOTAL FAILURES
15%OF TOTAL FAILURES
Drill Pipe Tube Fatigue
Tension
BHA Connection Fatigue
Torsion
Connection Leak
Tension / Torsion Combination
Sulfide Stress Cracking
Collapse
Split Box
Burst
Mechanical Failure of Specialty Tools Welding Failure
Page 73
DRILL STRING FAILURE
DRILL PIPE FATIGUE
DRILL PIPE TUBE FATIGUE FATIGUE FAILURE POINT OF ATTACK TTACK INTERNAL UPSET
SLIP AREA
TUBE MIDDLE
TRANSITION ZONE
LOCATION OF FAILURE
CAUSE
16" to 24" from pin and box end
Sharp change in wall thickness between tooljoint and pipe tube
16" to 24" from box end
Using one tong, stopping the string with the slips, worn slips and bowl
Middle section between pin and box
Contact with abrasive formation while rotating causing OD wear
First 5 stands above BHA
Stiffness change from BHA to drill pipe, possibility of compressional loading with excessive WOB
FACTORS THAT THAT ACCELERATE DRILL PIPE TUBE FATIGUE FATIGUE Slip cuts No transition pipe Doglegs and high angle holes Corrosive mud, oxygen, H2S, carbon dioxide, chlorides Running bent pipe Running drill pipe in compression Backreaming with high tension loads, torque and tension in combination Drill string vibrations and vertical bouncing Erratic torque, slip/stick drilling condition .
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 above the slips if possible Always use 2 tongs to make-up and break-out connection 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 transition pipe (HWDP) between 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 FATIGUE CORRECT TONG USE
TONGS AT AT 90 ANGLE IN 2 PLANES PLANES
90
LOAD CELL
LOAD CELL
90
INSPECTION COLOR CODE
DRILL PIPE / TOOLJOINT COLOR CODE IDENTIFICATION TOOLJOINT AND DRILL PIPE CLASSIFICATION BANDS
CLASS 1 ....................... 1 WHITE BAND S D N A B N O I T A C I F I S S A L C T N I O J L O O T & E P I P L L I R D
PREMIUM CLASS ........ 2 WHITE BANDS CLASS 2 ....................... 1 YELLOW BAND E P I R T S N O I T I D N O C T N I O J L O O T
CLASS 3 ....................... 1 BLUE BAND CLASS 4 ....................... 1 GREEN BAND SCRAP .......................... 1 RED BAND
TOOLJOINT CONDITION STRIPS
SHOP REPAIRABLE ..... 3 RED STRIPS OR SCRAP FIELD REPAIRABLE ..... 3 GREEN STRIPS CLASSIFICATION OF DRILL PIPE BODY
Page 75
DRILL STRING FAILURE
DRILL PIPE FATIGUE
IDENTIFICATION IDENTIFICATION MARKINGS O N TOOLJOINT
STANDARD WEIGHT DRILL PIPE GRADES X, G & S
DRILL PIPE WEIGHT CODE NOMINAL STD or SIZE SIZE WEIGH WEIGHT T T/WAL T/WALL L CODE CODE
GROOVE NEAR BOTTOM OF TOOLJOINT
3-1/2" 13.30
STD
1
15.50
TW
2
14.00
STD
2
15.75
TW
3
STD
2
20.00
TW
3
22.82
TW
4
19.50
STD
2
25.60
TW
3
21.90
STD
2
24.70
TW
3
25.20
STD
1
.
WEIGHT CODE
4" .
2 G
4-1/2" 16.60 .
GRADE CODE
.
INTERNAL UPSET
5"
MILLED SLOT
.
5-1/2" .
THICK WALL DRILL PIPE GRADES X, G & S
6-5/8" GROOVE NEAR TOP OF TOOLJOINT
DRILL PIPE GRADE CODE 3
E - E75
G
X - X95 INTERNAL UPSET
G - G105 S - S135 S135
IDENTIFICATION IDENTIFICATION MARKINGS ON TOOLJOINT DRILL PIPE IDENTIFICATION IDENTIFICATION
USS 694 N S
API BENCHMARK
CODE
USS
- Tooljoint manufacturer
694
- Date of tool joining (June, 1994)
N
- Tube manufacturer code (see RP7G)
E
- Drill pipe grade
USS 694 N S
Page 76
DRILL STRING FAILURE
BHA FATIGUE
BHA CONNECTION FATIGUE FAILURE
POINT OF ATTACK
C AU S E Tension from connection torque and BHA weight . Bending load increases neck tension on the outer side of the bending radius . Corrosion pitting
PIN NECK
Bending load applies circumferential stress BOTTOM OF THE BOX
Box OD wear reduces box strength Corrosion pitting
FACTORS THAT ACCELERATE BHA CONNECTION FATIGUE Over or under torquing the connection, under torquing is more common . Doglegs / high angle holes Corrosion from oxygen, H2S, carbon dioxide, chlorides Unstabilized drill collars in compression Large diameter holes or washed out holes BHA vibrations and vertical bouncing High tension load or jarring on stuck pipe No connection stress relief features Damaged connection sealing surfaces Incorrect Bending Strength Ratio (BSR) Erratic torque, slip/stick drilling conditions
PREVENTIVE ACTION Maintain hole angle change under 3 /100' Maintain sufficient levels of corrosion inhibitors and oxygen scavengers Apply recommended recommended make-up torque with with tongs at 90 angle in two planes and calibrate tong gauges frequently Correct recommended make-up torque (RMUT) for dope friction factor RMUT o = RMUT x Dope Friction Friction Factor Factor Minimize BHA vibration/buckling with stabilizers, shock subs Inspect the BHA at recommended intervals and after severe circumstances Cold-roll BHA connection thread roots Specify stress relieved pins and bore back boxes Maintain bending strength ratio (BSR) near value recommended for drill collar size
Page 77
DRILL STRING FAILURE
BHA FATIGUE
BHA CONNECTION STRESS RELIEF FEATURES
Stress relief features are designed to more evenly distribute the bending load through the connection
NO STRESS STRESS
PIN STRESS RELIEF GROOVE
RELIEFGROOVE
NO UNENGAGED THREADS
UNENGAGED THREADS
NO BOREBACK
BOREBACK BOX
CONNECTION BENDING STRENGTH RATIO (BSR) T e ratio of bo stiffness stiffness to pin stiffness stiffness . After applying proper proper torque, bending strength strength of connection is balanced balanced when the box stiffness is 2.5 times the pin stiffness
A BSR of 2.5 represents a balanced balanced connection for the average average size collar collar and connection type. type. As collar OD decreases, decreases, BSR should be reduced to compensate compensate for a weaker box. As collar OD increases, increases, BSR should be increased to compensate compensate for a weaker pin
BALANCED CONNECTION
) S E L C Y C ( E F I L E U G I T A F
MAXIMUM LIFE
STRONG BOX
STRONG PIN
1.5
2.0
2.5
3.0
BENDING STRENGTH RATIO RATIO (BSR)
Page 78
3.5
DRILL STRING FAI FAILURE LURE
CARE/HANDLING
DRILL CREW 5-SECOND CHECKS DEVELOP A REGULAR HABIT OF DOING 5-SECOND 5-SECOND CHECKS. THESE CHECKS CAN BE MADE ON THE PIPE RACK, RACK, V-DOOR, RIG FLOOR, WHILE DRILLING/TRIPPING, AND LAYING LAYING DOWN THE DRILL STRING. MARK AND SET ASIDE BAD JOINTS
BOX END INSPECTION Use a soft bristle brush and solvent to clean the threads and shoulder for a visual inspection Caliper for minimum required OD. Inspect for cracks, eccentric wear (out-of-roundness), (out-of-roundness), severe tong cuts or unusual damage Look for small or missing connection bevel . Visually inspect the sealing shoulder and threads for impact damage, pitting, galled surfaces, correct connection type, and belled boxes Check the BHA connections for bore-back feature
TUBE INSPECTION Visually inspect the slip area for deep slip cuts, severe pitting, bent joint Visually inspect 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) Visually inspect the tube for corrosion pits or unusual damage Check pipe for straightness when rolling on the pipe rack
PIN END INSPECTION Use a soft bristle brush and solvent to clean the threads and shoulder for a visual inspection Check pipe weight / grade stencils on pin neck / flat Compare grooves on toojoint for pipe identification Caliper minimum required OD 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 stretched pin Look for small or missing connection bevel Check the BHA connections for stress relief groove feature Look for abnormal connection ID's that are not consistent with the string
Page 79
DRILL STRING FAILURE
CARE/HANDLING
DRILL STRING FAILURE WARNING SIGNS C A U TI O N
HIGH RISK
When failure occurs, others may follow
Mud corrosion level is high
Drill string history is unknown
Doglegs are present
Pulling or jarring on stuck pipe
Abnormal torque, drag, drag, vibration
Picking up unfamiliar equipment
High angle hole
RECOMMENDED DRILL STRING CARE AND HANDLING PRACTICES D R I LLI N G
TRIPPING
Keep the mousehole and rathole clean
Alternate and record the break on each trip 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 above slips when making/breaking
Always use 2 tongs to make-up and break-out connections. connections. Use a pipe spinner to spin-up and back-out connections
Use correct dope compound for the specific connection. Dope threads and shoulder generously
Never apply the tongs on the drill pipe tube
Do not roll the pin into the box, pick up and re-stab
If a connection requires excessive break-out torque or the 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 make-up and break-out connections connections Watch for these signs on trips: Use a pipe spinner to spin-up and back-out connections
Shoulder Shoulder damage damage Belle elled d box box Stre Stretc tche hed d pin pin
Use proper make-up torque for the specific connection
Worn or missing missing bevels bevels Galle alled d or burn burned ed thre thread ads s Ecce Eccent ntri ric c box/ box/tu tube be wear 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 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 RMUT x Dope Friction Friction Factor Factor Do not roll the pin into the box, pick up and re-stab the connection
Use a steady pull to torque-up the connection
Monitor both make-up and break-out torque, break-out torque should be 80 - 100% of make-up torque
.
Page 80
DRILLING JARS
DRILLING JAR ADVANTAGE
A drilling tool designed to deliver high impact "hammer" blows to the the stuck stuck drill string
immedi diat ate e and corr correc ect t applica Highe gher prob robabili ility of rec recovery very with ith imme ication tion of jar blo blows
BASIC JAR SECTIONS OPEN
INNER MANDREL
8"
COCKED 8"
CLOSED
OUTER BARREL
SPLINE DRIVE
LATCH MECHANISM
LOWER SEAL WASH PIPE
HYDRAULIC JAR LATCH LATCH
OVERPULL APPLIED
COCKING JAR
Hyd. Oil Flowing By Piston
Trapped Oil Stops Upward Movement eme nt of Mandre Mandrell
JAR LATCH TRIPS
Oil Flowing By Piston
Metered Flow Delays Latch Trip
Page 81
DRILLING JARS PUMP OPEN FORCE (POF) Force of circulating or trapped pressure pushing the jar to the open position
LOWER SEAL
WASH PIPE
N S O I B T L A L 0 U 0 0 C , 0 R I 2 C
PRESSURE DROP = 2000 psi WASHPIPE WASHPIPE AREA = x 10 sq in P/O FORCE = 20,000 lbs
2000 PSI
BOTTOM AREA OF WASHPIPE, 10 SQ INCHES
See jar manual for POF information for your jar make, model and size POF AFFECT ON COCKING THE JAR (MECH OR HYD) COCKING FROM OPEN POSITION
More difficult or impossible to cock. Slow stop pumps or bleed trapped pressure before cocking
COCKING FROM CLOSE POSITION
Makes the jar easier to cock
POF AFFECT ON MECHANICAL JAR BLOW ADVANTAGE DISADVANTAGE
Less string tension requred requred for an up-jar blow
More set down weight weight required for a down-jar blow. blow. Slow / stop pumps or bleed trapped pressure when jarring down
POF AFFECT ON HYDRAULIC JAR BLOW ADVANTAGE
Intensifies the up-jar blow
.
DISADVANTAGE
Dampens the down-jar blow. blow. Slow /stop pumps or bleed trapped pressure pressure when jarring down
Page 82
DRILLING JARS COCKING THE JAR MINIMUM WEIGHT INDICATOR READING TO COCK THE JAR (MECH / HYD) COCKING FROM CLOSED POSITION
COCKING FROM OPEN POSITION = 330,000 Lbs = 30,000 30,000 Lbs = 10,000 10,000 Lbs = 20,000 20,000 Lbs = 270,000 Lbs
Last recorded slack-off wt - BHA wt below jar - Internal jar friction - Pump open force = Wt. Indicator load
= 330,000 Lbs = 30,000 30,000 Lbs = 10,000 10,000 Lbs = 310,000 Lbs
Last recorded pick-up wt - BHA wt below jar + Internal jar friction = Wt. Indicator load POF will ASSIST cocking the jar
POF will OPPOSE cocking the jar, slow down or stop the pumps or bleed trapped pump pressure to make the jar easier to cock
The force required to move the inner mandrel through the seals
CALCULATING TRIP LOAD MECHANICAL JAR DOWN-JAR BLOW Last recorded slack-off wt - BHA wt below jar - Dn-jar trip load setting - Pump open force = Wt. Indicator load
UP-JAR BLOW Last recorded pick-up wt - BHA wt below jar + Up-jar trip load setting - Pump open force = Wt. Indicator load
= 330,000 Lbs = 30,000 30,000 Lbs = 40,000 40,000 Lbs = 20,000 20,000 Lbs = 240,000 Lbs
= 330,000 Lbs = 30,000 30,000 Lbs = 80,000 80,000 Lbs = 20,000 20,000 Lbs = 360,000 Lbs
After cocking the jar, pump pressure can can be increased to reduce reduce pick-up weight required to trip the jar
Slow down or stop the pumps or bleed trapped pressure to reduce the slack-off weight required to trip the jar
HYDRAULIC JAR DOWN-JAR BLOW Last recorded slack-off wt - BHA wt below jar - DESIRED* DESIRED* trip load load - Pump open force = Wt. Indicator load
UP-JAR BLOW Last recorded pick-up wt - BHA wt below jar + DESIRED* trip load - Pump open force = Wt. Indicator load
= 330,000 Lbs = 30,000 30,000 Lbs = 50,000 50,000 Lbs = 20,000 20,000 Lbs = 230,000 Lbs
Slow down or stop the pumps or bleed trapped pressure to reduce the slack-off weight required to trip the jar
= 330,000 Lbs = 30,000 30,000 Lbs = 80,000 80,000 Lbs = 20,000 20,000 Lbs = 360,000 Lbs
After cocking the jar, pump pressure can can be increased to reduce reduce pick-up weight required to trip the jar
TRIPPING THE JAR MECHANICAL JAR DOWN-JAR BLOW
UP-JAR BLOW
After cocking cocking the jar, jar, slack off off to the calculated calculated weight indicator load
After cocking the jar, pick up to the calculated weight indicator load
No delay time is required, the latch will trip when the preset trip-load is applied to the jar
No delay time is required, the latch will trip when the present trip-load is applied to the jar
If the jar does not trip, slow down or stop the pumps or bleed trapped pump pressure to reduce pump open force
If the jar still does not trip, increase circulating pressure to maximum to increase increase the pump open force. 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, jar, slack-off to the calculated calculated weight
After cocking the jar, jar, pick-up to the calculated calculated weight indicator
indicator load
load
Lock down the brake and and wair for the jar time to elapse. 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 t rapped 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) FROM CLOSED POSITION:
(1) DRILL STRING IS RAISED
UP-JAR OPERATING SEQUENCE (MECH OR HYD) FROM OPEN POSITION:
(3) WEIGHT IS SLACKED OFF
(5) BHA MASS IS ACCELERATED BY GRAVITY
HW DP
(1) WEIGHT IS SLACKED OFF
(3) DRILL STRING STRETCHES AS TENSION IS APPLIED
(5) DRILLSTRING CONTRACTS
HW DP
(6) BHA MASS IS ACCELERATED
DC
DC DC
DC
8"
8" O
(4) JAR LATCH TRIPS
(2) JAR COCKS
(6) IMPACT IS DELIVERED
(2) JAR COCKS
(4) JAR LATCH TRIPS (7) IMPACT IS DELIVERED
STUCK PIPE
STUCK PIPE
Page 84
DRILLING JARS JAR OPERATIONS
REASONS FOR JAR NOT TRIPPING MECHANICAL JAR
HYDRAULIC JAR Jar not cocked . Not waiting long enough . Stuck above jar . Jar failure . Pump open force not considered . Pick-up /slack-off weight incorrect . Excessive Excessive hole drag .
Jar not cocked . Stuck above jar . Jar failure . Pump open force not considered . Pick-up /slack-off weight incorrect . Unknown /incorrect trip load setting . Excessive hole drag . Right-hand torque trapped in torque sensitive jar
JAR HANDLING
JAR HANDLING RECOMMENDATIONS RECOMMENDATIONS If a service connection connection is found loose, call the shop for recommended recommended torque. Do not use tooljoint tooljoint torque on these connections 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 mechanical jar jar is shipped shipped in the the cocked position. position. Run the jar jar in the extended extended or cocked cocked position position . Rack a mechanical jar in the derrick in the cocked position at any position in the stand . A hydraulic hydraulic jar is shipped shipped with a safety safety clamp clamp on the inner mandrel. mandrel. The jar must must be run in the open open position position . Rack a hydraulic jar in the derrick with the safety clamp at any position in the stand
DRILLING ACCELERATOR An energy st oring device d esigned to op timize the drilling jar ass embly for m aximum up and dow n jar-blow intensity
Allows optimu m jar placem ent Intensifies the jar blow
ADVANTAGES
Protects the drill string and rig surface equipment from high impact loads Compensates for insufficient drill string stretch in shallow holes Compensates for excessive drag in high angle holes
Page 85
DRILLING JARS DRILLING DRILLING ACCELER ACCELERA ATOR ! ! L L U P R E V O
INNER MANDREL
OUTER BARREL SPLINE DRIVE S D N A P X E N E G R O T I N
NITORGEN COMPRESSED BY APPLIED OVERPULL
NITROGEN (2000 psi)
S D N A P X E N E G R O T I N
LOWER SEAL
WASH PIPE
BHA MASS ACCELERATED
ACCELERATOR ACCELERAT OR OPERATING OPERATING SEQUENCE OVERPULL APPLIED
JAR COCKED
JAR LATCH TRIPS
1 WEIGHT
3
SLACKED
OVERPULL
OFF
APPLIED DP
HW DP
4 ACCELERATOR ACCELERATOR
6
STROKES OUT
BHA ACCELERATED
ACC 5
2
JAR LATCH TRIPS
JAR COCKS
DC JAR
JAR
DC
JAR
7 JAR BLOW DELIVERED
Page 86
DRILLING JARS BASIC JARRING RULES STRING STATIC STATIC when when sticking occurred
JAR DOWN
STRING MOVING UP when when sticking occurred
JAR DOWN
STRING MOVING DOWN when when sticking occurred
JAR UP
In 70% of sticking occurrences, down jarring is required. Jar /accelerator placement programs are available through jar service companies
DRILLING JAR ASSEMBLIES ASSEMBLIES (< 60 HOLE ANGLE) JAR ASSEMBLY
JAR / ACCELERATOR ASSEMBLY
DP
DP
HW DP
HW DP
WEIGHT FOR UP AND DOWN JAR BLOW
WEIGHT FOR DOWN JAR BLOW
EQUAL TO DOWN-TRIP LOAD
1.2+OF DOWN-TRIP LOAD ACCEL
WEIGHT FOR UP JAR BLOW
JAR
0.2 OF UPTRIP LOAD
DC
DC
DC
JAR
DC
DC
Page 87
DRILLING JARS JAR SIZE AND PLACEMENT GUIDELINES 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 accelerator in the HWDP section). Use the largest jar size (OD) for the hole size size
JAR SIZE
HOLE SIZE
9 " Jar
17-1/2" 17-1/2" and larger larger
8" Jar
12-1/4" to 17-1/2"
6-1/2"
8-3/4" to 12-1/4"
4-1/2"
6-1/2" to 7-1/8"
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, 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 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 circulating pressure. The jar will remain in the open position (if circulation 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/acce jar/accelerator lerator placement plac ement advice
Page 88
DRILLING JARS Y L B M E S P S D A R A J
R A J
: R A S J D N E A V T O S B A
C D
R A J W O L E t : B W
P D W H
) 0 6 : - A 0 ( H B T E E H r S t o K c a R F t O W W T N E S M N E O I C T A A L D P N E R M O M T O A C R E E R L E C C A / R A J G N I : L E Z I L I S R E L O D H Y L B P D M E S S A C C A / R A J
C D
) 5 . F 7 A 5 ( . 4 S 6 . R 1 . O 7 T 7 . C 7 A 2 . F 8 7 E 8 . L 1 . G 9 N 4 9 . A 7 . E 9 L 9 9 O < . . H 9 0 1
: S D N A T S
: B O W
0 6 5 5 0 5 5 4 0 4 5 3 0 3 5 2 0 2
5 1
0 1
0 . 9 0 2
P O T
M T B
6 . ) F 1 7 . B ( 3 7 . S 4 R 7 . O 6 . T 7 C 7 7 . A 9 F 7 . Y 0 . C 8 2 N 8 . A 3 Y 8 . O 5 . U 8 B 0 . 6 0 . 9 1 0 . 8 1 0 . 7 1 0 . 6 1 0 . 5 1 0 . 4 1 0 . 3 1 0 . 2 1 0 . 1 1 0 . 0 1
Y L B M E S S A R O T A R E L E C C A / R A J
Y L B M E S S A R A J
9 8 .
R O T A R E L E C C A
: - S N D R N W A O J A D T S
: S - D N P R A A U J T S
. 1
. 2
R A J
C D : - T W H R G O L A I J E E B W
P D W H
Page 89
C D : S D N A T S
: B O W
DRILLING JARS
: A H B
) 0 6 > ( T E E H S K R S O N I W O T T A N D E N M E E M C M O A C L E P R R O T A R E L E C C A / R A J G N I L e : L I i s R l e D o H
Y L B M E S S A C C A / R A J
D E T M A U I P H M T I C T I A X T T A N P E I B M A D
0 6 e h t n e e w t e b g a r d n w o d d e t a m i t s e s u l p
) 0 5 F 6 . 7 A 5 5 ( 5 . 4 0 S 5 6 . R 1 5 7 O 4 . T 0 7 . C 4 7 5 2 A 3 . F 8 0 7 8 E 3 . L 5 1 . G 2 9 4 N 0 2 9 . A 7 5 . E 1 9 L 0 9 1 9 O < . . H 9 0 1
R A J
: G S N D I N R A R T A S J
0 . 9
. 1
. 2
. 3
: P D l l s a d w n a d r t a S d n a t S
9 8 .
. 5
. 4
P D W H
G N R I O T T C A A - R E E L L B E U C O C D A
6 2 . ) 0 F 0 . 1 9 7 1 . B ( 0 . 3 8 7 . S 1 0 . 4 R 1 7 7 . O 0 . 6 7 T 6 1 . 0 . 7 C 5 7 . A 1 0 . 9 F 4 7 1 . Y 0 . 0 8 C 3 1 . 0 . 2 N 2 8 . 1 A 0 3 . Y 1 8 . O 1 0 . 5 8 U 0 1 . B 0 . 6
r o t a r e l e c c a e h t d n a e l g n a e l o h
Y L B M E S S A E L B A R E E T S
: - S N D R N W A A O J D T S
P D W H
P D
Page 90
E L G N A L 0 E 6 O H
WELL CONTROL WELL PRESSURE CONTROL
The control of formation fluid flow (kick) into the wellbore
THE THREE PHASES OF WELL CONTROL PHASE
DEFINITION
OBJECTIVE
Control of kicks with hydrostatic pressure (HSP) only
Drill to total depth without a well control event
SECONDARY (Second Line Line Of Defense) Defense)
Control of kicks with HSP assisted by blowout preventer equipment
Safety kill the kick without the loss of circulation
TERTIARY (Third Line Line Of Defense) Defense)
An underground underground blowout blowout
Avoid Avoid a surface surface blowo blowout. ut. Regain Regain primary well control
PRIMARY (First Line Line Of Defense) Defense) .
.
Te ltimate oal of ell pressre ontrol is to prevent a srfae bloot
PRIMARY
THE PRIMARY CONTROL TOOL HYDROSTATIC HYDROSTATIC PRESSURE (HSP)
The pressure developed by the height and density of a non-moving fluid column PPG = LBS PER GALLON FLUID DENSITY . 0.052 = PPG TO PSI/FT CONVERSION FACTOR . TVD = TRUE VERTICAL DEPTH (FT) HSP =MUD .O52 TVD PSI PPG . =10.0 =10.0 .052 10,000 . =520 =5200 0 PSIHSP HSP
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
FORMATION PRESSURE
HSP HSP 5200 PSI
Page 91
4700 psi
WELL CONTROL
PRIMARY
SWAB / SURGE PRESSURES PRESSURE
DEFINITION
SWAB
TRIP MARGIN
NOTES
The piston affet of upward string movement causing a derease in well-bore pressure which can induce a kick
Maximum swab pressure occurs at the bit and is equally imposed to the bottom of the wellbore . As string motion motion is started, additional surge pressure pressure is imposed to break the gel strength of the mud and accelerate the mud column
Marginal over-balance pressure (i.e., 300 - 500 psi) to compensate for swab pressure
The hsp overbalance is more often dictated by hole stability (i.e., 800 - 1000 psi)
affe t of downward string The piston affe movem ovemen entt caus ausing ing an in rease in wellellbore pressure
SURGE
PUMP SURGE
Maximum surge pressure occurs at the bit and is equally imposed to the bottom of the wellbore . As string motion motion is started, additional surge pressure pressure is required to break the gel strength & accelerate the mud column
The pump pressure required to break the gel strength of the mud and accelerate the mud column
6500
Pump surge pressure to break circulation can be (in some cases) greater than the normal circulating pressure
LOSS OF CIRCULATION / UNDER GROUND BLOWOUT FRACTURE PRESSURE =6200 psi
6000
STATIC 5500 E R U S S E 5000 R P
E T A R E L E C C A
STEADY SPEED
E T A R E L E C E D
STATIC
E T A R E L E C C A
E T A STEADY SPEED R E L E C E D
STATIC
S P M U P T R A T S
STEADY CIRCULATION CIRCULATION
ANNULUS FRICTION PRESSURE
SURGE
HSP =5200 psi SWAB TRIP MARGIN
FORMATION FORMA TION PRESSURE =4700 psi
4500
KICKS / HOLE INSTABILITY INSTABILITY 4000 TIME
Page 92
WELL CONTROL
PRIMARY
EQUIVALENT CIRCULATING DENSITY (ECD) The mud wt equivalent to the sum of hydrostatic and annulus friction pressures at a true vertical depth of interest
0'
Ann Fric psi +MW TVD TVD Ft X .052 .052
) ( 400 = (10,000 X .052 ) +10.0
ECDppg = 2500'
A N N U L U S F R I C T I O N P R E S S U R E = 4 HYDROSTATIC 0 0 PRESSURE P S 5200 PSI I
TVD 5000'
7500'
10,000' 0
1
2
3
4
5
ppg
= 10.8 ppg ECD
6
7
PRESSURE (1000 psi)
ADVANTAGE
DISADVANTAGE
Built-in safety factor during a kick killing operation . Safety factor if circulating near or slightly under balance to formation pressure
Penetration rate decreases as ECD increases . Increases potential for lost circulation, differential sticking, wellbore instability
KICK TOLERANCE The maximum under balance kick load (ppg), considering an estimated kick volume, the casing shoe can tolerate without fracturing
EVENT
EFFECT ON KICK TOLERANCE
Casing shoe drill out . True vertical depth increase . Mud weight increase
Maximum kick tolerance for hole section Decreases kick tolerance Decreases kick tolerance
KICK TOLERANCE APPLICATION APPLICATION Indicates the next casing depth to maintain well control safety . Input to risk analysis if decision is made to drill ahead
Page 93
DRILLING JARS
PRIMARY
GUIDELINES FOR MAINTAINING HYDROSTATIC PRESSURE (HSP) MUD WEIGHT MAINTENANCE ACTION
RESPONSIBILITY
Weigh and record mud weight in and out every 30 minutes during any circulating operation .
Shaker man Derrick man
Driller Mud Engineer
Driller Mud logger Shaker man
Geologist Drilling Engineer Company Rep
Company Rep Mud Logger Toolpusher
Geologist Drilling Engineer
.
Monitor the well for signs of changing formation pressure . . Ensure mud weight is correct before drilling into known high or low pressure zones .
Mud Engineer Shaker Man Derrick Man
Ensure a means of disposing of contaminated fluid to avoid contaminating the mud system .
Shaker Man Derrick Man
Ensure proper mud weight is used to fill the hole on trips . Maintain pit valve seals to avoid accidental dilution
NOTIFY
Driller Toolpusher Company rep
Driller Mud Engineer
Maintain degasser capacity to handle full returns
MUD COLUMN MAINTENANCE ACTION
RESPONSIBILITY
Ensure proper hole fill during trips . Use a calibrated trip tank. Appoint a dedicated trip tank man. man. Record hole fill volumes during round trip . If the correct fill-up is not taken (swabbing indicated), flow check the well. If not flowing, return return to bottom bottom and circulate bottoms up
Driller Mud Logger Trip Tank Man
NOTIFY
Company Rep Drilling Engineer Toolpusher
If the correct displacement volume dows not return while tripping in, (lost circulation indicated), stop tripping and observe the well. If lost circulation occurs, pump water (WBM) or base oil (OBM) down the annulus. If the well is flowing, shut-in the well immediately
Maintain mud box seals, ensure drain is plumbed to the trip tank or annulus if filling with pump strokes .
A/D Floor men
Compant Rep Toolpusher
A/D Driller
. Company Rep Toolpusher
. Maintain hole full during non-criculating operations
Page 94
WELL CONTROL
SECONDARY
SECOND LINE OF DEFENSE KICK
The loss of hydrostatic pressure control of formation fluid flow into the wellbore
SECONDARY WELL CONTROL
ASSISTED by blow The The contro controll of forma formatio tion n fluid fluid flow flow by the use of hydro hydrosta static tic pressu pressure re ASSISTED blowout out preventer equipment
KICK TYPES
UNDER BALANCE KICK Kick caused by an increase in formation pressure above wellbore hydrostatic pressure
Under Balance Pressu Pressure re (U/ (U/B B psi )
500 psi SIDPP
500 psi U/B psi +300 30 0 psi ps i HSP HS P Loss
= 800 psi SICP
CAUSE : . PERMEABLE ZONE IS DRILLED DRILLED WITH MUD WT INSUFFICIENT TO CONTROL FORMATION FORMATION PRESSURE . WARNING: . PROGNOSED ABNORMAL FORMATION FORMATION PRESSURE . OFFSET WELL DATA INDICATIONS: . GEOLOGIST / MUD LOGGER ABNORMAL PRESSURE TREND CHANGES
5 0 0 0 p s i
TORQUE /DRAG INCREASE . DRILLING BREAK . WELL FLOW /PIT GAIN
FIRST ACTION: . SOUND KICK ALARM . POSITION DRILL STRING FOR SHUT-IN . STOP THE PUMPS /SHUT-IN THE WELL
4 7 0 0 p s i
Gas Kick 300 psi HSP loss
PREVENTIVE ACTION: . ADJUST MUD WEIGHT PRIOR TO TO DRILLING KNOWN ABNORMAL PRESSURED ZONE . OBSERVE ABNORMAL PRESSURE WARNING SIGNS
Sand
5500 psi Page 95
WELL CONTROL
SECONDARY
KICK TYPES
INDUCED KICK Kick caused by a decrease in hydrostatic pressure below formation pressure of a premeable zone
Under Balance Press Pressure ure (U/ (U/B B psi )
0 psi SIDPP
0 psi U/B psi +300 psi ps i HSP HS PLoss
= 300 psi SICP
NOTE:
A kick was swabbed in & the drill string stripped to bottom 5 0 0 0 p s i
4 7 0 0 p s i
U-Tubing Drill String HSP
Gas Kick 300 psi HSP loss
4700 psi
Sand Page 96
WELL CONTROL
KICKS
SECONDARY
KICK DETECTION TEAM
, R E E G T M R S I A A O B M
R E H T A E S W U / T M A T R S O F E T R A O L B P L L E W
R O N O E L M F
K N A T N P A I M R T
/ K R C E I N K R A A R M H E S D
T S I G O L O E G
A E . S G B N U E S
S N G I S G N I N R A W K C I K
P O B
, P U - W L O L I L F F E L L L E O W H
W O L F L L E W , N R U T E R S G N I T T U C
L A C I G H T O P L E O D E G
N O I T A R E P O
S U T A T / S
P I U Q E / L E N N O S R E P
L R N L E I - E L T L U W I R H E D S H T
. D G U N M E
S U T T A S
P I U Q E / L E N N O S R E P
L R E O S N I N V P & O R G T I S E R P R E U P S
N L A P
S N O I T I D N S O N C A E L R P O L B A L N L E O S I N T W A O I R T I E D P N O O C D U M N E O I R T U A S M S R E O R F P
L A & R C I D O G A R I T O T O N L A C O O D E E N E N R M G O O I R I T T U I A S I C M S R E D E O R F P R P
L A M C R I I G N F O A N L L O O P C E G
E G F N O A E H S C I V D N A A L P
, R D W . E L D G / G U G D N E M O W L M
Page 97
Y L B E D S N S A T E S V
N O S I T S E A N U I D C A A V E E R
S T N E M E R I U Q E R L A C I N A H C E M , N A L P L A N O I T A R E P O
S N O I T I D N O C L E S S E V / G I R , S T I M I L L A C I N A H C E M
E R
O R . O . P S I V O E B L R L C R E E P U W S
G T N R I O R P E P E N I U S G N E
. . G G L N R E D
WELL CONTROL
SECONDARY
DRILLING KICKS
CAUSES OF KICKS WHILE DRILLING UNDER BALANCE KICK
INDUCED KICK Lost circulation . Light mud weight pumped down hole . Swabbing while working the string / making connection . Core volume gas cut mud
Drilling into a permeable zone with a mud weight insuficient to control formation pressure
INDICATIONS OF UNDER BALANCE KICKS INDICATIONS
NOTES
RESPONSIBILITY
NOTIFY
LOGGER TRENDS INDICATE FP INCREASE
d exponent decrease, Shale density decrease, splintery shale cuttings, connection/background gas increase .
Mud Logger
Driller Co Rep Mud Logger Geologist
DRILLING BREAK
Indicates a new formation exposed to the well. Under balance kicks are usually preceded by an abrupt ROP change, increase or decrease
Driller Mud Logger
Co Rep Geologist Toolpusher
WELL FLOW
Kick fluids displace mud from the wellbore increasing increasing the return flow or causing well flow with the pumps off
Driller Mud Logger Shaker Man Derrick Man
Drl Crew Toolpusher Co Rep Mud Engineer
As kick fluids flow into the wellbore, wellbore, the volume volume addition is detected by the pit volume totalizer (PVT)
Driller Mud Logger Shaker Man Derrick Man
Drl Crew Toolpusher Co Rep Mud Engineer
Lower density kick fluid decreases annulus hydrostatic pressure allowing the drill string mud to u-tube to the annulus
. Driller Mud Logger
PIT VOLUME GAIN
PUMP PRESSURE DECREASE / SPM INCREASE
Page 98
Toolpusher Mud Eng Derrick Man
WELL CONTROL
DRILL KICKS
SECONDARY
INDICATIONS
INDICATIONS OF INDUCED KICKS LOSS OF MUD WEIGHT (LIGHT MUD PUMPED, SWABBED GAS , CORE GAS) INDICATIONS
NOTES
RESPONSIBILITY
NOTIFY
PUMP PRESSURE DECREASE / SPM INCREASE
Lower density kick fluid decreases annulus hydrostatic pressure allowing the drill string mud column to U-tube to the annulus
Driller Mud Logger
Toolpusher Derrick Man Mud Eng
WELL FLOW
Kick fluids displace mud from the wellbore increasing return flow or causing well flow with the pumps off
Driller Mud Logger Shaker Man Derrick Man
Drl Crew Co Rep Toolpusher Mud Eng
.
.
Driller Mud Logger Shaker Man Derrick Man
Drl Crew Co Rep Toolpusher Mud Eng
PIT VOLUME GAIN
As kick fluids fluids flow into the the wellbore, the volume volume addition is detected by the pit volume totalizer (PVT)
LOSS OF COLUMN HEIGHT (TOTAL LOSS OF CIRCULATION, NOT KEEPING HOLE FULL) INDICATIONS
NOTES
RESPONSIBILITY
NOTIFY
Driller Mud Logger Shaker Man Derrick Man
Drl Crew Co Rep Toolpusher Mud Eng
Loss of hydrostatic pressure may induce a kick
MUD COLUMN LEVEL DECREASE
FLOW CHECK GUIDELINES WHILE DRILLING SURFACE STACK
SUB SEA STACK Drill 3 to 5 feet of the break, observe for flow
Drill 3 to 5 feet into the break, observe for flow
.
.
If flow is detected, initiate shut-in procedure
If flow is detected, initiate initiate shut-in procedure Raise the kelly / top drive to the shut-in position Raise the kelly / top drive to the shut-in position Stop circulation, line-up the trip tank and observe for flow Stop circulation and observe for flow 5 to 10 minutes
5 to 15 minutes
.
.
Maintain slow rotation to prevent sticking potential
Maintain slow rotation to prevent sticking
If flow is detected, initiate shut-in procedure
If flow is detected, initiate shut-in procedure
Page 99
WELL CONTROL
SECONDARY
DRILLING KICKS
DIVERTER GUIDELINES WHILE DRILLING SURFACE STACK
SUB SEA STACK
Sound the kick alarm
Sound the kick alarm
Raise the kelly / top drive to shut-in position
Raise the kelly / top drive to shut-in position
.
.
Maintain fll irlation
Maintain fll irlation
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 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 depleti depletion on ma tae several ors or das
SHUT-IN GUIDELINES WHILE DRILLING SURFACE STACK
SUB SEA STACK
Sound the kick alarm
Sound the kick alarm
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, necessary, adjust annular preventer operating pressure
If necessary, necessary, adjust annular preventer operating pressure
relative to stabilized SICP
relative to stabilized SICP
Page 100
WELL CONTROL
DRILLING KICKS
SECONDARY
CONDITIONS REQUIRED PER KICK TYPE The kick type must be identified to determine the proper kill procedure. Using the incorrect kill procedure increases the potential for loss of circulation
KICK TYPE UNDER BALANCE KICK
REQUIRED CONDITIONS Occures only while drilling Abnormal formation presssure produces an under balance kick kick SIDPP is some value above standpipe hydrostatic pressure
INDUCED KICK
Can occur during any open hole operation All formation pressure pressure classifications classifications can produce produce an induced kick kick SIDPP is equal to standpipe hydrostatic pressure
BEST KILL PROCEDURE FOR KICK TYPE UNDER BALANCE KICK
INDUCED KICK
WAIT WEIGHT METHOD WITH BALANCE KILL MUD WEIGHT A constant bottom bottom hole pressure method method to prevent
CIRCULATION CIRCULATION METHOD DRILLER'S WITH PRESENT MUD WEIGHT A constant bottom bottom hole pressure method to prevent
additional kicks
additional kicks
.
.
Minimizes kill kill pressures imposed imposed to wellbore and
Minimizes kill kill pressures imposed imposed to wellbore and equipment
equipment
.
.
Kills the kick in one bottoms-up circulation
Kills the kick in one complete circulation
MOMENT OF MAXIMUM SHOE PRESSURE UNDER BALANCE KICK
INDUCED KICK
WAIT WEIGHT METHOD WITH BALANCE KILL MUD WEIGHT
CIRCULATION METHOD WITH PRESENT MUD WEIGHT
AT SHUT-IN
If shut-in pressures are contained without fracture, the probability of a successful kill is greater than 90%
AS GAS REACHES SHOE
The depth of the influx at shut-in is seldom known. Actual bit-toshoe strokes cannot cannot be determined. Follow Circulation Method Method kill procedure
Page 101
WELL CONTROL
SECONDARY
KICKS
KICK CONTROL TEAM , R E E G T M R S I A A O B M
R E H T A E S W U / T A M T R S O E F T R A O L B P L L E W
D E D E E N S A T S I S S A
/ K R C E I N K R A A R M H E S D
E T A P R T E P O
A E . S G B N U E S
R N O E O L M F
R E E N I G N E D U M T S I S S A
S U T T A S S / U T N A O I T T S A P I R E U P Q O E / N L P E O L A N B P N P I O U S R Q E E / P L E N N O P S R R E M E P T
E L L I R D
A R E P O
U P L L I K
Y L B E D S N A S T E S V
N S O I T S A E I U N C D A A V E E R
E K O H C
S T N E M E R I U Q E R L A C I N A H C E M , N A L P L A N O I T A R E P O
S N O I T I D N S S O N N C , . O A I E T T L R N P A I R O L A E B A M P L N L & O O E I N M T W O A I O R T O E A R P R D E O P U . E M R D G P E E U N D S E N U R M E O M E I V L . . . . E L S I O P - T K A O
S N O I T I D N O C L E S S E V / G I R , S T I M I L L A C I N A H C E M
E R C R R E
E V P O O
, R D . E W L G D G / U G D N M E O W L M
& A R D T R A O D T I O L N C E L O R I M K
Page 102
G T N I R O R P E E P N I U S G N E
. . . . G G L R N D E
WELL CONTROL
WELL WE LL CO CONT NTRO ROL L
SECONDARY
WAIT & WEIGHT METHOD FOR UNDER BALANCE KICKS Monitor shut-in pressures for gas migration while making preparations for the kill operation . If observed, bleed mud from the annulus to maintain SIDPP at stabilized shut-in value plus 50 - 100 psi safety factor . Calculate kill mud weight (KMW) . Over Ov er bala balanc nce e in the the kmw kmw or addi additi tion onal al chok choke e pres pressu sure re is not re ommended nor nor requ requir ired ed for for a safe safe kill kill oper operat atio ion n . Construct a drill pipe pressure schedule . When preparations are complete, start the kill operation: . srf srfa a e sta sta - hold casing pressure at shut-in value while while increasing pump to kill rate . sbsea sbsea sta sta - hold kill line pressure at shut-in value value while increasing pump to kill rate . Hold pump speed at kill pump rate (KPR) and adjust the choke for proper drill pipe pressure versus strokes . When KMW reaches the bit, continue holding pump at kpr and adjust the choke for final drill pipe pressure until KMW returns . Sub sea stack: remove any gas trapped in the bop stack and displace the riser with KMW KMW . Open the BOP and check the well for flow . Condition mud system, increase to trip margin density
CIRCULATION (DRILLER'S) METHOD FOR INDUCED KICKS Monitor shut-in pressures for gas migration while making preparations for the kill operation . If observed, bleed mud from the annulus to maintain SIDPP at initial shut-in value plus 50 - 100 psi safety factor . An increase in the present present mud weight or additional choke pressure is not recommended for a safe kill operation . When preparations are complete, start the kill operation: . surface stack - hold casing pressure at shut-in value while while increasing pump to kill rate . sub sea stack - hole kill line pressure at shut-in value value while increasing pump to kill rate rate . With the pump at kill pump rate, record the observed circulating drill pipe pressure . Hold pump speed at kill pump rate and adjust the choke to maintain maintain the recorded drill pipe pressure value until bottoms up strokes are pumped Sub sea stack: remove any gas trapped in in the BOP stack . Check the well for flow. flow. Condition the mud system
Page 103
WELL WE LL CO CONT NTRO ROL L
SECONDARY
KICKS
REMOVING GAS TRAPPED BELOW THE BOP Close the lower pipe ram to isolate the wellbore from the stack gas clearing operation Open the kill line failsafe valves. valves. U-tubing pressure from choke line will 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. water. Allow pump pressure to increase as water water is pumped Close the kill line failsafe valves Open the choke line completely to allow the trapped gas to expand into the choke line Line up the trip tank to maintain the riser full When expanding flow from the choke line stops, open the annular preventer completely to allow the riser to utube 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 valves and displace the riser with KMW. KMW. Displace choke line with KMW KMW Open the lower ram and check the well for flow
Page 104
WELL WE LL CO CONT NTRO ROL L
TRIPPING KICKS
SECONDARY
CAUSES OF KICKS WHILE TRIPPING Only Only Induce Induced d Kicks are possib possible le during during the trippi tripping ng operat operation ion Swabbing ( 1 cause of kicks) Improper hole fill procedure Lost circulation Filling the hole with light mud weight Weighing Material Sag
INDICATIONS INDICATIONS OF INDUCED KICKS INDICATIONS HOLE NOT TAKING CORRECT FILL-UP
RESPONSIBILITY
NOTES The barrels of mud required to fill the hole is less than the steel volume pulled .
Over pull generally associated with swabbing
NOTIFY
Driller Trip Tank Man Mud Logger
Mud eng. Co.rep. Toolpusher
Driller Trip Tank Man Mud Logger
Drilling Crew Mud eng. Co.rep. Toolpusher
.
Kick fluids displace mud from the wellbore causing well flow with pumps off WELL FLOW
.
Primary well control is lost when the well begins to flow .
PIT VOLUME GAIN
As kick fluids flow into the wellbore, the volume addition is detected by the pit volume totalizer (PVT)
.
Driller Trip Tank Man Mud Logger
Drilling Crew Mud eng. Co.rep. Toolpusher
FLOW CHECK GUIDELINES WHILE TRIPPING SURFACE STACK
SUB SEA STACK
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
.
If flow is detected, initiate shut-in procedure
Page 105
WELL WE LL CO CONT NTRO ROL L
SECONDARY
TRIPPING KICKS
DIVERTER GUIDELINES WHILE TRIPPING SURFACE STACK
SUB SEA STACK
Sound the kick alarm
Sound the kick alarm
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 diverter
Make-up top drive /kelly and pump the heaviest available fluid at maximum rate .
Prepare to abandon the location
Make-up kelly /top dirve and open safety valve Open pump suctions to the heavy mud reserves and pump at maximum rate
Monitor the sea surface for gas. Move the rig up wind of surfacing gas Fill pits/tanks with sea water
Build additional heavy mud volume
Continue pumping the heaviest fluid available at maximum rate
Prepare to abandon the rig
.
Gas one depletion ma ta e several ors or das a s
SHUT-IN GUIDELINES WHILE TRIPPING SURFACE STACK
SUB SEA STACK
Sound the kick alarm
Sound the kick alarm
.
.
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 .
Open the upper choke line fail-safe valves
Open the choke line valves
.
.
Close the upper annular preventer with 1500 psi closing pressure pressure
Close the annular preventer with 1500 psi closing pressure
.
.
Record SICP every 2 minutes
Record SICP every 2 minutes
.
.
Adjust annular annular preventer preventer closing closing pressure pressure relative relative to stabilized SICP
Adjust annular annular preventer closing closing pressure relative to stabilized SICP .
Maintain string movement to prevent sticking
Maintain string movement to prevent sticking
Page 106
WELL WE LL CO CONTR NTROL OL
TRIPPING KICKS
SECONDARY
EVALUATE THE OFF BOTTOM KICK CONDITION KICK CONDITION
DESCRIPTION
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)
The drill string is pulled out of the hole before the kick is detected
NO PIPE IN HOLE
RECOMMENDED ACTION PER KICK CONDITION HEAVY PIPE STRIP BLEED OPER.
Strip the drill string to bottom and kill the kick using the Circulation Method with present mud weight
.
LIGHT PIPE SNUBBING OPER. Snub drill string into the wellbore until string weight is sufficient for stripping operation
PIPE OUT OF HOLE SNUBBING OPER. Snub drill string into the wellbore until string weight is sufficient for stripping operation
IF STRIPPING OR SNUBBING IS NOT POSSIBLE (I.E., STUCK PIPE) VOLUMETRIC METHOD
VOLUMETRIC METHOD
VOLUMETRIC METHOD
.
Allow the gas to migrate migrate above above the bit. Kill the kick using the Circulation Method with present mud weight
.
Allow the gas to migrate above the bit. Kill the kick using the Circulation Method with present mud weight
IF THE INFLUX DOES NOT H EAVMIGRATE MU MUD CA CAP
Allow the gas to migrate to surface. Kill the kick using a Dynamic Lubricate and Bleed procedure
IF THE GAS MIGRATES TO LUBR ICSURFACE ATE BLEED
LAST RESORT OPTION BULLHEAD
.
Circulate kill mud weight of sufficient density to kill the casing pressure .
Open the BOP and run to bottom .
Kill the kick using the Circulation Method with present mud weight
Pump present mud weight across the well head, through the choke and back to a small calibrated pit .
Decrease casing pressure by PSI/BBL equivalent per barrel of mud loss in the pit
Page 107
Use only under special conditions .
Pump present mud weight to fracture pressure and inject influx into formation .
If shoe fractures first, an under ground blowout will occur
WELL CONTROL
SECONDARY
KICKS
STRIP AND BLEED GUIDELINES Calculate the maximum allowable surface pressure (MASP) to avoid formation fracture MASP MASP = (Fra (Frac c ppg - Mud Mud ppg ) X .052 .052 X TVD TVD shoe 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 Bbls/std = (Pipe disp + cap) X Stand Length . Route Route the return returns s from from the choke choke manifo manifold ld to the trip trip tank. tank. Sub Sea Stack If necess necessary ary,, displa displace ce the choke choke line line with with presen presentt mud weight Adjust the annular preventer closing pressure pressure for stripping. Route the lubricating lubricating mud volume to the trip tank Apply 100 - 200 psi psi safety factor. factor. Hold the choke closed closed and strip 1 - 2 stands until safety factor is reached (SICP + SF). If necessary, 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 with present mud weight to kill the kick kick
11 10 )
) 0 0 0 0 1 1 ( ( i i s s p p g g i n i n s s a a C C
Overbalance restored as bit reaches bottom
9 8 7
Bit below influ
Influ Influ disp disp DC annulus
6
Influ Influ pushed pushed up hole by pipe disp
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 stop stripping operation. Use the Circulation Method with present mud weight and 100 -200 psi safety factor factor to circulate a portion of the influx out. out. Continue stripping to bottom
Page 108
WELL CONTROL
KICKS
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 - Mu Mudppg ) X 0. 0.052 TVDshoe X TV . 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. 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 the choke closed closed and allow casing pressure to increase 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 Use the the Circ Circul ula atio tion Metho ethod d wit with pres presen entt mud mud wei weight ght and and - psi safety factor
to circ irculat ulate e the gas gas out of the hole ole
. 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 Gas At Bit
50 psi Increase
9
Bleeding B/BBLs
SICP ) ) 8
0 0 0 0 1 1 7 ( ( i i s s 6 p p g g n i n i 5 s s a a C C 4
Gas Displacing DC/DP Annulus SIDPP
3 2 Gas Above Bit
1
Safety Factor
0 7
8
9
10
Time (Hrs)
Page 109
11
12
13
14
WELL CONTROL
SECONDARY
KICKS
DYNAMIC LUBRICATE & BLEED GUIDELINES Line-up returns from the choke manifold to the gas buster and on to a small calibrated pit. The cementing unit is ideal for this operation. . Line-up the pump discharge to the kill line . Calculate the barrels of pit level decrease required before allowing the casing pressure to decrease by 50 psi (LUB BBLs) .
LUB BBLs = Bbls/Ft csg X 50
Mudppg
0.052
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 casing pressure at it's shut-in shut-in value while increasing the pump speed speed - Increase pump speed to 1 - 2 barrels per minute. Maintain Maintain SPM onstant during the kill procedure Apply a 50 psi safety factor. factor. Adjust the choke choke to maintain casing pressure at it's shut-in value 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
)
0 0 1
(
i g
C
p
s
i n s a
) 0 0 1 ( i s p g i n s a C
6 5
Calculated Csg Pressure
4 3 2 1
50 psi Safety Factor 0
0
15
30
45
60
75
90
105
120 135 150
165 1 80 80
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 Open the BOP and check the well for flow
Page 110
WELL CONTROL
UGB
TERTIARY
THIRD LINE OF DEFENSE UNDER GROUND BLOWOUT
An under ground diversion diversion of high pressure pressure kick fluids
.
TERTIARY WELL CONTROL
Methods employed to contain an under ground blowout and regain primary well control
UP-FLOWING UNDER GROUND BLOWOUT (UGB) Kick fluids from a deep zone flows upward into a lower pressure shallow zone
LOSS ZONE
HIGH PRESSURE KICK ZONE
Page 111
TERTIARY
WELL CONTROL DOWN-FLOWING DOWN-FLOWING UNDER GROUND GROUND BLOWOUT BLOWOUT (UGB) Kick fluids from a shallow zone flows downward into a lower pressure deep zone
KICK ZONE
LOW PRESSURE LOSS ZONE
Page 112
UGB
WELL WE LL CO CONT NTRO ROL L
UGB
TERTIARY
INDICATIONS INDICATIONS OF UNDERGROUND BLOWOUTS (UGB) UP-FLOWING UGB
DOWN-FLOWING UGB
Shut-in pressure build up begins to decrease
Total loss of circulation
Casing pressure fluctuations during shut-in stabilization period
Electric wireline surveys can be used to determine if a down-flowing UGB is occurring
Shut-in casing pressure continues to increase while shut-in drill pipe pressure remains constant
Shut-in pressures are zero initially
Partial or total loss of circulation Shut-in pressures fall to zero psi
GUIDELINES FOR DOWN-FLOWING UGB The loss zone must be repaired before remedial action can be taken at the kick zone
TREATING THE LOSS ZONE
Consult your Mud Engineer for the most applicable "flash setting" lost circulation plug(s) After pumping the LCM plug in place, place, start filling filling the annulus with with the present mud mud weight to control control the kick zone When the annulus fills up, stop the pump and check the well for flow If possible, keep the hole full If flow is observed, shut-in and record pressures KILLING THE KICK
Use the Circulation Method (Driller's) with present mud weight to kill the kick zone
Page 113
WELL WE LL CO CONT NTRO ROL L
TERTIARY
UGB
GUIDELINES FOR UP-FLOWING UGB Kick zone pressure must be controlled before remedial action can be taken at the loss zone
HEAV HEAV PILL PILL
Determine the true vertical measurement between the kick zone and loss zone (TVD K-L) Determine or or estimate the formation formation pressure pressure of the kick zone (FPKICK) Determine or or estimate the formation formation pressure pressure of the loss zone (FPLOSS) Calculate the the kill mud weight weight required required to kill the kick zone (KMW PPG)
(
KMWPPG =
)
(FPKICK - FPLOSS) + SAFETY FACTORPPG TVDK-Lx .052 .052
If KMWPPG equals the density density capacity capacity of of the weighting material, refer to the Heavy Heavy Pill/Gell Pill/Gell Pill Pill Guidelines Guidelines If KMWPPG is greater greater than the density density capacity capacity of the weighting weighting material, material, refer to the Barite Plug Plug Guidelines Guidelines Build KMWPPG volume equal to 2 to 3 times the the open open hole hole volume. volume. If possible, possible, remove 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 at maximum rate HEAV HEAV PILL PILL GELL GELL PILL PILL COMBINA COMBINATIO TION N
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 annulus pump speed to place place the gel pill at the loss loss zone as the heavy heavy pill reaches the bit. bit. Continue to pump the heavy pill at maximum rate BARITE BARITE PLUG PLUG
A barite plug works best best with gas blowouts. High flow rate salt water blowouts blowouts wash the barite into the 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
WELL WE LL CO CONT NTRO ROL L
OPERATIONS
SOLUTION GAS
Gas that has dissolved into the base oil of oil base mud
BUBBLE POINT PRESSURE
The pressure and temperture condition that will allow the gas to break out of solution
UNDETECTABLE UNDETECTABLE KICKS IN OIL BASE MUD The sensitivity of the pit volume monitoring system system cannot detect vomume vomume changes under +/- 5 barrles. A small kick volume volume can enter the wellbore ompletl ndete ted.
WATER BASE MUD
OIL BASE MUD 0'
0' 0'
Bubble Point 1000' - 2000' 100% Of Total E pansion
12 bbls Gas Volume
2500'
2500'
No E pansion
Detectable Pit Gain
Depth
Depth 5000'
5000'
6 bbls Gas Volume
10,000'
No E pansion
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 until a near surface bubble point pressure is reached Gas solution in OMB does not hinder hinder the detection of large volume kicks kicks (> 5 bbls). Normal kick detection detection applies. After shutting in the well, nor norma mall i illi illin n pro pro edre edres s appl appl
Page 115
WELL WE LL CO CONT NTRO ROL L
OBM
OPERATIONS
OPERATIONS THAT CAN MASK A KICK Seepage /partial loss of circulation Mud weight adjustments and transfers while drilling Solids control and degassing the mud system Spills and leaks in surface equipment Loss of volume on connections /trips Pump start-up and shut-down volume change 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 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 surface as solution gas will not migrate. Use recommended procedure to circulate bottoms up after all short or round trips
SOLUTION GAS AT SURFACE If rapidly accelerating well flow occurs, the Driller must respond immediately Regardless of kelly /top drive position, stop the rotary and pumps, close the annular preventer (Sub sea, close the diverter) Strip the drill string to the proper shut in position Use standard well control procedures to kill the kick
Page 116
WELL CONTROL P C F
P C I
E R U S S E E R L P U E D P E I P H C L S L I R D ) E (
T E E H S L L I K L O R T N O C L L E W
E R U S S E R P S E K O R T S
A T A D L L E W ) A (
) ) ) ) ) ) ) ) ) ) 0 1 2 ( 3 ( 4 ( 5 ( 6 ( 7 ( 8 ( 9 ( 1 ( ( o t t s i k B t S
g p p
S N O I T A L U C L A C ) C (
: S N O I T C U R T S N I
t h g i e W d u M l a n i g i r O + + ) ) 2 2 5 5 0 . 0 .
) W M O ( t h g i e W d u M l a n i g i r O
g p p
) D V T ( h t p e D l a c i t r e V e u r T
s k t S l i t n u t n e m e r c n i h c a . e d o e t c h c n I a r s e k i s t S t i d B d o A t
r e p h e c s a a c e e e r m . D o c I d e r e d S f h c c P e r e a u D e s I r s s S e i r P p P t = c C e 0 a p F r l i 1 t i p l t b l i n r . ) u s u d t P , t e n n t e C P C e a m F I l m u e c r m e P o l r c c a i C r n n I C ( F i . 3 .
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. t n e m e r c c n n I r I s e k p t e S s a e r c n i s = e k 0 1 o r t s t i e B t o a t l u s c k l a t C S . 2 .
P P D I S + e r u s s e r P p m u P l l i K = P C I
t f
+
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E R U D E C O R P T H G I E W & T I A W ) D (
W M K x e r u s s e r P p m x u P l l i K = = P P C C F F
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m p s
t i B o t s e k o r t S
l . a i e t i u f l n i a I . t v n a t o P h t i g a P i e r D g I W i S m d n u s i a M a t g l n l i r i o a K f o s m t o t r t i e p u d n s s u i m t e r h p d g n e i e . e i l - b e w t u u , l d h r y u s a v r a m o s i s n e t i t s n e i c u a o e h R M n s . . 1 . 2
s k t s
Page 117
A T A D K C I K ) B (
p m . u e P k o o h t r c e n f o e r l , l e e t e w l e p h t m o g c i n r e r b a d s n n a o i e t r a r u a d p e c e r o r p l l p i k p U n t e r h t a W S . . 3
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i s p
d n a e n e l i - P h u t t d u O t e h B s h s u j c k m d S c o a r e f r d e h s u c n s a a s d g t e n r n r a a a P t e e l s k C n e . o p o i s h c l p n r c k ) l i c r t u e t a R D h t e P r K e t e S ( h h s a e o S e t g l t n i i c a e r t a , b u p i n W p S m m a d u u . u m s p M p e . l o l e l r l r i t i h u e k e K t s s l d s i r i p l k o t o e o h l n t r l i H c u S p k . . . 4 . 5
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i s p
. w o l f r o f k c e h c d n a P O B e h t n e p O . . 6
O O n i a G t i P
s l b b
WELL CONTROL
S E R U D E C O R P P U T R A T S P M U P
S K C A T S E C A F R U S
e l i . h r e w u y l t s s h r e g p i l s g n e i k s o a h c c g e i n h t r v n e e s p b O o ) 1 (
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t h g i e w y v a e H
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) ) s l S b L b ( B l B o ( V E = M ) t U / f l L b O b V ( p a G C N I R ) f T t ( S h L t g L I n e R L D
= =
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.
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L L E W D L L N I = A K ) K T O T U S T / P S T S L E B U ( K B O T O U P R P M T T U S U O P L P A M U T P O T
, r R e p e P r o l K p u s e d e e h h t h c c S a r o e f e r e r u p k o s m h s u c r p e e P e h e h t t t i p n s l p e j u l h d i r W a D ) 4 (
t i B o t s k t S
=
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) s l b b ) ( S l o L V
) E T I T / I F S C L A B P B A ( C
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g
n S i s H a ) T T C G F ( x N P E D L
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, r R e p e P r o l K p u s e d e e h h t h c c S a r o e f e r e r u p k o s m h s u c r p e e P e h e h t t t i p n s l p e j u l h d i r W a D ) 4 (
o t s n . i g p e b m e u p r u l l i s k s e e r h p t e t r a n t i l l l s , i k e s s a a e t s r c u e J d ) 2 (
H O x P D
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Page 118
=
=
=
x
x
x
g = n i r t S l l i r D y b e x l o H n e p O ) 2 (
=
=
=
x
x
x
s k t S s u l u n n A
s e k o r t S e c a f r u S o t t i B
=
=
s K k T t S S / n S r o L f i o B n t a B m l u u l c o r c i l d C o d l a V A t o s T u l u n n A
) y l n o a e s = b = e u s m ( u l e r o o V m f u s n u l l o m u u V l n e x o c n n A i d l d a L t A e o k T o h C ) 3 (
CASING CEMENTING Pipe designed to meet the requirements for setting at a specified depth
CASING
The process of displacing the casing annulus with cement to provide hydraulic integrity and zone isolation
CEMENTING
CEMENT CLASS API provides nine classes of cement to allow allow for various pressure pressure /depth /temperature /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 cement slurry densities densities can be obtained using various additives additives
25 ) g p20 p ( y t i s n15 e D y r r u l 10 S 5
Conventional Ultra Lightweight Lightweight
Neat
d e i f i s n e D
d e t h g i e W
Heavily weighted
ALIT Y CO N NT R T O R L A L QU T O O T Successful Cement Job
Trainin Trainingg Technolog Technologyy Technique Techniquess Knowledge Operator
Service Rig Companies Contractor Team Concept Attitude Attitude Commitme Commitment nt
Dedicatio Dedication n Communica Communication tion
CEMENTING PHILOSOPHY
Page 119
CASING CEMENTING
ADVERSE CONDITIONS THAT AFFECT CEMENTING IMPROPERLY DRILLED HOLE
POOR MUD CONDITION
Small hole ID, doglegs, washouts /breakouts, wellbore unstable, incorrect casing seat selection
High gel strengths and yield point, high fluid loss, thick filter cake, high solids content, loss circulation material, mud /cement compatibility
LOST CIRCULATION
Loss zones not sealed before cementing. Excessive Excessive circulating annulus pressure causes cement loss. Scratchers remove protective protective LCM
ABNORMAL PRESSURE
Complicates well planning /drilling. /drilling. Heavy tubulars reduce clearances, clearances, high density slurries require more control, pipe movement more difficult, liner problems
. SUBNORMAL PRESSURE
Differential sticking, cement filtrate loss, low density slurries, reduced strength .
WATER SENSITIVE FORMATION . HIGH TEMPERATURE
Sands with clay sensitive to fresh water filtrate, water block in dry gas zones
Mud gelation, flash sets cement without retarder, casing elongation /contraction problems, down hole tool limitations, cement strength retrogression
SUCCESSFUL CEMENT JOB GUIDELINES Condition mud to stabilize wellbore and to achieve optimum but safe rheological values Continuous pipe motion during mud conditioning and cementing operations Pump as much spacer as practical ahead of the cement Utilize as many centralizers as practical to center the casing in the wellbore Properly design cement slurry rheology High displacement pump rates improve cement placement. placement. Formation conditions determine determine the pump pressure window Prevent cement /mud contamination Know wellbore formation fracture pressure limitations
CEMENT JOB EVALUATION METHODS Shoe pressure test
Tracer survey
Temperature survey
Production test
Cement bond log
Page 120
CASING CEMENTING STANDARD EQUIPMENT
RUBBER PLUGS (TOP & BOTTOM)
SCRATCHER
FLOAT COLLAR
CENTRALIZER
GUIDE SHOE
Page 121
CASING CEMENTING
CASING PREPARA PREPARATION TION GUIDELINES Ensure thread protectors are installed when handling casing Ensure casing is racked racked safely. safely. Use adequate stripping for each casing casing layer to prevent bending /buckling. /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 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. casing. Unidentified joints should not be run Ideally, Ideally, the casing should be cleaned, inspected, measured and drifted before the next layer is placed on the rack Remove thread protectors, clean clean the box and pin and protectors. Clean any debris from inside the casing casing . Reinstall clean pin and box protectors hand tight Any damaged joint and those that do not drift should be marked with red paint paint and laid aside Four persons are required to measure casing. casing. One person on each end of the tape, another in the center to prevent 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
WELLBORE PREPARA PREPARATION TION GUIDELINES Record bottom hole temperature on logging runs, trip back to bottom after logging operations prior to running casing 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 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 trip out, the problem must be corrected 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 to run casing. These values will be used to evaluate evaluate the drag /set down trends when the casing is on bottom and reciprocation begun Requirements for successful wellbore cementing are: . - Wellbore that has a diameter at least 1-1/2" (preferably, 2" - 3") larger than casing OD . - Near gauge wellbore without washouts . - Wellbore without severe doglegs . - Stabilized wellbore without hole problems, lost circulation, gas, water flow or well control problems Select a competent casing casing shoe. Consider the casing strap and space space out accordingly At casing point TD, condition hole with GPM rates at least as high as the expected expected cementing pump pump rates
Page 123
CASING CEMENTING
DRILL RIG PREPARATION PREPARATION GUIDELINES GUI DELINES Install proper casing rams in the correct position in the BOP. BOP. Test the opening and closing of the BOP 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. line. Ensure proper number of block lines are strung to handle the casing hook load in air Visually inspect inspect dead line anchor, hook, traveling and crown blocks. Magna flux or ultrasonic inspection should be considered for heavy hook loads Inspect braking system on the drawworks Visually inspect 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 stabbing board is available and in proper operating condition Ensure adequate size casing fill-up line with control valve is rigged up If necessary, necessary, clean a mud pit for spacers or pipe releasing pill . Ensure adequate water storage available for cement job and possible loss of circulation Remove wear bushing before running casing
Page 124
CASING CEMENTING
CASING OPERATIONS PRE JOB CHECKLIST Casing cleaned, tallied and drifted . Casing joints numbered in order of running by thread type and weight . Crossover subs checked. Damaged joints laid laid aside . Calculate the casing strap for landing joint space out. Casing collar should be ten feet minimum distance from casing head flange. Ideally, Ideally, cementing head should be 5 - 15 feet above above the rotary table . Rathole below the casing shoe should be +/- 5 feet for surface wellheads, 15' - 20' for sub sea wellheads and mud line suspension operations . Maximum safe tension load calculated on weakest upper casing joint /coupling . Cementing head on location. Proper thread type and function tested tested . Guide /float shoe, float collar collar on location. Proper thread type and function function tested . Stage cementing or liner hanging equipment on location. Proper thread type and function tested . Centralizers /scratchers /scratchers on location. Type Type /size /number /spacing determined from electric logs /well plan . Cementing plugs on location. Type /size /size and rupture pressure on bottom plug verified . Casing head /slips /hanger /ring gasket /pack-off /pack-off on location. Size /type /pressure rating verified. Flange bolts size size /number checked . Casing slips /elevators /elevators on location. Size /type verified verified . Power /manual casing tongs on location. Heads /dies /condition /condition checked . Stabbing boards on location, in good operating condition . Proper casing thread compound and thread locking compound on location . All snub lines checked for operational operational safety . Clamp-on thread protectors /size /number on location . Pipe rack area /pipe handling equipment inspected for safety . Combined casing /drill string /cement loads within rig's rating. If not, string up additional lines or lay down set back weight . Wear bushing removed /casing rams installed . All service companies companies notified notified for timing sequence sequence of events (cementing and casing casing crews, inspection inspection services, services, nipple-up services, test companies)
Page 125
CASING CEMENTING
RUNNING CASING GUIDELINES Clamp-on thread protectors are recommended when picking up casing Observe correct make-up procedures. Ensure torque gauge on on tongs is accurate. accurate. Use API thread compound Ensure casing cementing head is properly dressed with top /bottom plugs and proper cross overs Install centralizers /scratchers according to predetermined plan Utilize a casing running schedule to monitor casing displacement trends for losses /gains Run surge /swab pressure calculations. calculations. Communicate the proper running speed 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 lock compound to the pin ends of float 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 Ensure proper stabbing procedures are used to minimize thread damage Fill casing every five joints minimum depending depending on casing size. Communicate fill-up schedule schedule to casing crew The casing should be landed no further than 20 feet form bottom 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
CEMENTING OPERATIONS PRE JOB CHECKLIST Determine maximum allowable cement density density to prevent formation fracturing. If allowed, cement density should be at least 1 ppg heavier and preferably 2 - 3 ppg heavier than the drilling fluid Determine bottom hole cementing temperature from logs Design cement slurry for specific job using company or industry specifications specifications Design preflush /spacers to be displaced in turbulent flow. 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, 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. 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 should be made for stage collar cementing Calculate the theoretical weight of the casing in 1000 feet intervals Calculate time, volume and strokes required to displace pipe after casing is on bottom and to circulate one complete circulation Calculate the volume of mud required to displace cement Estimate the annulus cement velocities anticipated during the various stages of the job Estimate the top of cement in the annulus Double check all volume calculations with cement company representatives on location prior to cementing
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CASING CEMENTING
CEMENT JOB MONITORING GUIDELINES Drilling Forman should identify top and bottom wiper plugs. Make sure the plugs are properly installed in the cementing head . Cementing head should be installed installed in the V-door if possible. All connections to to the cementing head should be in place and ready for immediate hook-up . Pressure test all lines from cementing unit to casing head to 3000 - 5000 psi . Begin reciprocation and mud conditioning immediately immediately after the casing reaches bottom. Casing reciprocation need not be fast. Select a stroke length between 15 - 30 feet that will not position a coupling in the wellhead. Take 1 - 3 minutes to complete a stroke cycle depending on hole conditions . Ensure that full returns are present or rate of mud losses are consistent with losses noted earlier . Condition mud such that gel strengths, plastic viscosity, viscosity, yield point and mud density are as low as possible without dropping out solids or creating a wellbore stability problem . Condition hole with GPM rates equivalent to anticipated cementing pump rates . Circulate and condition mud /hole for a minimum of 100% hole volume or 1 - 1-1/2 casing volume. In-and-out mud weight should be equal and the shakers should be clean . Monitor pick-up and slack-off drag trends while reciprocating. reciprocating. Stop reciprocation with casing near bottom if drag trends indicate sticking tendency . Batch mix the spacer spacer and cement slurries if practical. practical. Observe mixing operation, operation, collect wet and dry samples. samples. Weigh and record slurry continuously using a pressurized pressurized balance and an in-line densitometer during the job. Observe surface setting time and free water separation of wet samples . Record surface pressure /pump /pump rate on a continuous recorder for the entire entire job. Record total cement mixing mixing and displacement time . A typical cement cement job sequence sequence of events: pump the spacer, spacer, release the bottom bottom plug, pump the the cement, release release the top plug, clean cement from surface lines and displace cement until the top plug bumps . As soon as all cement has been pumped, drop the top plug, Check valves / indicators on cementing head to to verify plugs did release. NEVER ALLOW THE CEMENT IN THE ANNULUS TO STOP MOVING MOVING WHEN PLUG IS RELEASED . Observe mud returns for losses, gains, return of preflush or cement to surface . Slow the pump rate to bump the plug on the float float collar. Bump the plug with the proper pressure, 500 500 - 1000 psi over circulating pressure or sufficient sufficient for a casing pressure test. Hold 5 -15 minutes, release the pressure and check the floats . If floats hold, leave casing open during WOC time. A small amount of back-flow is expected due to heat expansion . If plug does not bump at the calculated pump strokes, over displace the plug by no more than the volume between the float collar and shoe
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CASING CEMENTING
POST CEMENTING OPERATION OPERATION GUIDELINES If float fails, and apply approximate pressure the plug was bumped with. Hold pressure until initial cement strength is developed, monitor pressure. Heat will cause pressure build-up, bleed if necessary to maintain initial pressure 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, assembly, caliper casing OD A wellhead manufacture's manufacture's representative representative should be present for slip, packoff packoff and casing 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 must be clean, dry and free of burrs or nicks. nicks. Do not grease the ring gasket All nuts and bolts bolts should be clean clean and the correct size. All nuts should should be tightened evenly 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 equivalency or leak-off leak-off test in the new hole is necessary necessary to determine determine the effectiveness effectiveness of the the cement seal and the formation fracture gradient
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CASING CEMENTING
CEMENT PROBLEM DETECTION
Monitoring cement jobs by continuously measuring pump rate, rate of returns, surface densities and pressures can provide early detection of some cementing problems
TROUBLE SHOOTING CEMENTING PROBLEMS CEMENT CHANNELING
UNSUSPECTED WELLBORE WASHOUT
LOST CIRCULATION
INFLUX CONDITION
DOWN HOLE RESTRICTIONS
CEMENT SLURRY DEHYDRATION
Mud poorly conditioned before start of cementing operation . Cement free-fall period ends before anticipated due to higher annulus pressure . Surface pressure higher than expected . Lower rate of returns through free-fall stages Cement free-fall period remains longer than anticipated due to decreased annular pressure . Surface pressures are lower than anticipated after free-fall . Reduced rate of returns when washout encountered followed by increased returns rate in near gauge annulus . Erratic returns after free-fall period Well comes out of free-fall later than expected . Surface pressures are lower than anticipated . Rate of flowline returns is lower than expected . Free-fall inside casing is strong strong due to reduced annulus hydrostatic hydrostatic pressure. Might be indicated by strong vacuum at cementing head Well comes out of free-fall later than anticipated . Surface pressures are lower than expected . Rate of returns are higher than anticipated during and/or after free-fall period Well goes on free-fall later and comes out of free-fall sooner than expected . 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 during deceleration, then level off off before coming out of free-fall Free-fall starts approximately when expected but ends prematurely due to higher frictional pressures . Surface pressures are higher than expected . Rate of returns normal until dehydration starts then begins to decrease
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HORIZONT HORI ZONTAL AL DRILL DRILLING ING
HORIZONTAL WELL
A wellbore drilled parallel the the bedding plane of a production zone
WHY DRILL HORIZONTAL WELLS
LIMIT PRODUCTION OF UNWANTED FLUIDS
OL
MAXIMIZE PRODUCTION
OL
PENETRATE VERTICAL FRACTURES
OL L
OL
INCREASE PRODUCTION OL
LO
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HORIZONT HORI ZONTAL AL DRIL DRILLING LING
HORIZONTAL WELL PORFILES
S U I D A R T R O H S
' t 0 S F 2 / U I 4 O T D o ' A T 0 R 6 1 o
o
T F 0 0 4 T F 0 0 5 2 T F 0 0 0 4
S U I D A R M U I D E M
' ' 0 0 0 S 0 3 1 / U I 0 O 2 T D ' A o 0 R 0 T 7 8 o
o
' 0 ' 0 0 0 0 1 S 1 / O U I 6 T D ' o 0 A T 0 R 0 1 6
S U I D A R G N O L
o
o
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HORIZONTAL DRILLING BHA
ANGLE BUILDING ASSEMBLY ASSEMBLY SHOR HORT RADIU DIUS KNUC NUCKLE KLE JOINT MEDIU DIUM RADI ADIUS DOUB DOUBL LE BEND MOTOR KICK PAD
BENT SUB DUMP VALVE
KNUCKLE JOINT
MOTOR SECTION
MOTOR SECTION
ADJUSTABLE BENT HOUSING
THRUST BEARINGS
THRUST BEARINGS ROTATING SPINDLE
ROTATING SPINDLE
LONG & MEDIUM RADIUS ADJUSTABLE ADJUSTABLE BENT HOUSING
DUMP VALVE
MOTOR SECTION ADJUSTABLE BENT HOUSING THRUST BEARINGS ROTATING SPINDLE
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HORIZONTAL DRILLING HORIZONTAL HORIZONTAL WELL PLAN FOCUS PLANNING
GEOLOGY
DRILLING FLUID
HYDRAULICS
WELLBORE STABILITY
CONSIDERATIONS Formation type . Rock strength /stress . Porosity /permeability . Mud type . Inhibition . Mud weight . Drill string size . Down hole tool restrictions . Pump capacity . Over burden stress . Trajectory profile . Washout /breakout
Formation pressure Formation dip angle
Rheology Hole cleaning
Formation type
Hole closure Lost circulation /Gas influx Cuttings bed
HORIZONTAL HORIZONTAL OPERATIONS OPERATIONS FOCUS OPERATIONS RIG
DRILL STRING
WELL CONTROL
WELL LOGGING
CASING
CEMENTING
CONSIDERATIONS Top drive . Pump capacity . Drill pipe size . BHA design .. Down hole motors . Torque /drag BOP equipment . Kick detection . Gas behavior . MWD / LWD . Drill pipe conveyed /Coil tubing . Pump down method Casing design . Slotted liners . Predicted pick-up /slack-off weights . Slurry design . Mud condition . Contamination
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Solids control equipment
Drilling jars Inspection frequency
Kill calculations
Centralizers Pipe movement
HORIZONTAL DRILLING
WELL CONTROL
E L O H F O D N E H G I H
T N E M E G R A L N E E L O H
S N O I T A I V E D E L G N A
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S A G
HORIZONTAL HORIZONT AL DRILLING P C K
P C I
E R U S S E E R L P U D E P I E H P L C S L I R D ) E (
T E E H S L L I K L O R T N O C L L E S N W O I L T L A A T U N C L O A Z C I ) R C ( O H
g p p
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E R U S S E R P S E K O R T S
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i s p
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) W M O g ( t p h p g i A e T W A d D u M L l L a n E i g i W r ) O
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S N O I T C U R T S N I
. . n d h r n d r o e t i c o d e e e t i c n t h p n c h n a e c c e . p I a u c . n n u a m a d d k t o e i o o P P d r e i e t . t e e r t t r r e i S O O h s c c r s c c B k e K K c i i u u i t a d r s e d n n o . t r s e e o I u P o d P t t h e s C . t = e r r . i u r i k c d e t C s s s t s t s i s e P s s K e . p e n S a e n F k a t e 5 t c e e r r r p e e i t l h m t i r i h i u O u B p l S i t t m c o p K , d t a e ) d B s n s n e e s s o n r r P i c u e u e t o e t h s r e c P d t o t t t h r C s n k t n r t n O a t P s p p I = S I F e s t , k P i = c n K P , c s t e C = c e e C 5 s a e P a r I K a m m 5 d P e t o O e S p p t r i 5 t e i d O k e C p k i p m b r l p m b r K l a s t l o o K s t u l l c c r t i k t o ) u n i o ) s n , K t o n , n r P s r f r f r r i i s u o P , P i S S d d S s t t P , h t C P h O k t t i C - t e K t e t e n C P c t e n F C c s t k n t I s k B t e a e K I i C a l a a o t a a e d o l t 0 S l B S m l r t e u m - K e m u u u o s c s m P l e e e c t c P m m l c m m o m r l c k l t k o i t l C r o c a r o o a r o o c I c K e t a S r C r n a s r r r n n n R S C F u C t i ( F f C i ( F f k F i C . . . S . . . 3 . ( . . 4 . . 5 . . . 1 . 2 . .
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. , . r y s r e . e n a s e t h r i s r u s . k t l o n l i e e h i r e c l a t u c t n k i . e - d n h t e n a i v n g u n o a i u f l a I n l l m e h a . i s s - e o v n t t o u w t W k a c g h i h g e d e k g t u h s i i k a n c e r l r o M c t a a g l i h i b W i t , c l i d s r . d m i n r K n e e a a w u s t u h l i t e l t o e l M a t n f g a d k l C l e u s i r P c u o - r o o P o j l e h K f f d u c k o s D c k I r p a t e a c e S p d d t r h t e t i e h p u n n i U a c e S h s c t a a n s t r t S s i e i o e d t r a n e l n t h p a S t a r c S n g , b a i s u n m p n p s u P e i - o m o s m S w t O t e u u c r u . B d h d s e u s u P R P p e e r t o P e h h m r m t p t u o K i t r e i p p s e l s n d d l s n e f i l o r e e e e o i p a o l r t R M b R H D S p O . . . . . . 1 . 2 . 3 . 4 . 5 . 6
) P O K ( t h t f p e D d e r u s a e M P O K
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s k P t O s K o t s e k o r t S
A T A D K C I K ) B (
) P P D I S ( e r u s i s s p e r P e p i p l l i r D n I t u h S
) P C I S ( e r i u s s p s e r P g n i s a C n I t u h S
s l b b
n i a G t i P
HORIZONTAL DRILLING
e f f t a o k m i c i o r k p e p h a t f e o h t E n t L o c D i e D t l e I c e S M s
d e r h u t p s e a e D M
T E E H S L L I K L O R T N O C L L E W L A T N O Z I R O H
l a c i t r h e t p V e e D u r T
D A E T A D D R O S C U E L R - U E N N R P A
A T D E A D D G R N O I C R E T R - S E L L R I P R D
=
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L L E W D L L N I A K T O U T P T S U E K O P O R M T U S P L A T O T
P O K
) s l ) b b S ( L l o B V B ( = . E ) f M t / l U b b L ( O p a V C
S ) E I T T / I F S C L A B P B A ( C
g
n S i s H a ) T T C G F ( x N E P L D
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S e H p ) i T T p l G l F i ( r N E D L
L
) S ) s l L b b B ( l B o ( V E = M ) U t / L f l b O ( b V p a G C N I R ) T t ( S f h L t g L I n e R L D .
t h g i e w y v a e H
s k t S s u l u n n A
t i B o t s k t S
s r a l l o C l l i r D
=
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k t s / s l b b
l o V g n i r t S
l o V s u l u n n A
o t s e k o r t t i S B
p U s s m e o t k o t r o t B S
) 1 (
) 2 (
=
g n i r t S l l i r x D y b g n i s a C
x
=
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g n i r t S l l i r D y x x b e l o H n e p O
) 1 (
=
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= e m u l o r V o f g n n i r m t u s l l o l i C r d D d l a A t o T
=
k t s / s l b b
l o V P g O n K i r t o S t e l d d i m o P t s O e K k f o o r t S
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Page 137
= s e k o r t r S o f n n i o t m a u l l u o c C i r d C d l A a t o T
k t s / s l b b
=
) P O K ( T N I O P F F O K C I K O T S E K O R T S
P O K o t s k t S
= e m u r l o o f V n s m u u l l o u n C n d A d l a A t o T
) 3 (
) S ) s l L b b B ( B ( l o P V O = K ) t f / l O b T ( b E p a M C U L O ) t ( V f h G t g N I n e R L T S .
=
=
x
x
) 1 (
) 2 (
= P O r K o t o f n e m m u u l o l o C V d g d n A i r t S
INVESTIGA INVEST IGATION TION PACKAGE DRILLER HANDOVER
WELL: R IG :
DATE:
D R I L LE R :
LAST CSG OD:
M D:
INITIAL O/PULL:
SHOE PPG:
PUMP 1 PRESS CLFP
TIME
H O LE S I Z E :
WT BELOW JAR:
DEPTH OF KILL PUMP RATE:
SPM
A/D :
DEPTH OF KILL PUMP RATE:
PUMP 2 SPM
OPERATION
PUMP 1
PRESS CLFP
DEPTH
MAX O/PULL:
RO ROP
PUMP 2
SPM PRESS CLFP
ROTATING WEIGHT
DEPTH OF KILL PUMP RATE:
PICK-UP
WEIGHT
SPM
PRESS CLFP
SLACK-OFF WEIGHT
: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 TYPE & DEPTH OF PROBLEM ZONE(S) DRILLED: TYPE & DEPTH OF PROBLEM ZONE(S) PROGNOSED: EQUIPMENT REPAIRED / ON-GOING:
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PUMP 1
RPM
PUMP 2
SPM SPM PRES PRESS S
CLFP LFP
SPM SPM PRES PRESS S
CLFP CLFP
OFF/B TORQ
ON/B TO TORQ
SPM
CIRC. PRESS
% RET
WO B
INVESTIGATION INVESTIGA TION PACKAGE SHAKER HANDOVER
WELL:
DATE:
RIG:
SHAKER MAN:
MUD ENG:
LAST CSG OD:
MD:
HOLE SIZE:
EQUIPMENT STATUS LOW SPEED SHAKERS
SH AKER 1
SHAKER 2
HIGH SPEED SHAKERS
SHAKER 1
HYDROCONES
SHAKER 2
DESA DESAND NDER ER
DESI DESIL LTER TER
CENT CENTRI RIFU FUGE GE
DEGASSER
TIME
OPERATION
DEPTH
CUTT CUTTIN ING G RET RET. Dec / Nor / Inc
*CUT *CUTTI TING NGS S TYPE
*CUT *CUTTI TING NGS S DESCRIPTION
WT. IN
VIS IN
WT. OUT
VIS OUT
COMMENTS
: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:
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