Technology & Training
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Training
to Reduce Unscheduled Events I
~y. .
AMOCO
~·~
Training to Reduce Unscheduled Events was compiled by the Amoco EPTG Drilling Technology Teams © 1994, 1995, 1996 Amoco Production Company Third Edition
,,
~y~ AMOCO
~·~
The materials were prepared by Amoco Production Company. Neither Amoco Production Company, employees of Amoco Production Company, nor any person acting on behalf of either: a.
Makes any warranty or representation, express or implied with respect to the accuracy, completeness, or usefulness of the information, contained in these materials, or that the use of any information, apparatus, method, or process disclosed in this report may not infringe third party rights: or
b.
Assumes any liability with respect to the use of, or for any and all damages resulting from the use of, any information, apparatus, method, or process in these materials.
TABLE OF CONTENTS TEAM BUILDING PRINCIPLES •
TEAM BUILDING PRINCIPLES .. ............................................................
1
•
BASIC GEOLOGY .................................................. .................
2
• • •
CASING PROGRAM ........ ................ .......... ................... ........... 9 DRILLING FLUIDS .................................................................. 15 HYDRAULICS PLANNING ...................................................... 20
.,-
-
..
• • • •
.
.. -...
~:-
•
.--
'
.
..
•
•
-. I ;
,..
.
.
-
•
·- .
HOLE PACK-OFF I BRIDGE ..................... ................ ................ DIFFERENTIAL STICKING ................ ...................................... WELLBORE GEOMETRY .................................................. ..... STUCK PIPE FREEING ................... ............ .............................
22 44
47 53
LOST CIRCULATION • • • • •
LOST CIRCULATION MECHANISMS ............. ........................ SEEPAGE LOSS SOLUTIONS ............................................ .... PARTIAL LOSS SOLUTIONS ................................................. TOTAL LOSS SOLUTIONS ............ ......................................... PILL SPOTTING GUIDELINES ... ............................................
56 60 61 61 63
RIO REPAIR •
IMPACT OF UNSCHEDULED RIG REPAIR ............................. 66
• •
INTERGRATING PMP WITH WELL PLAN ............................... 68 DRILLING SYSTEM EMERGENCY PROCEDURES ............... 69
•
TOOL FAILURE CAUSES ........................................................
•
•
70 FACTORS INFLUENCING TOOL SELECTION ....................... 71 RIG-SITE TOOL SELECTION /INSPECTION CHECK LIST. ... 72
DRILL STRING FAILURE
• •
DRILL PIPE FAILURE PREVENTION PLANNING ..............
•
BHA CONNECTION FATIGUE FAILURE ............................... BHA CONNECTION STRESS RELIEF /BSR .......................... DRILL CREW FIVE SECOND CHECKS .................................. DRILL STRING CARE I HANDLING PRACTICES ...................
•
• •
73
DRILL PIPE TUBE FATIGUE FAILURE .................................... 74 77
78 79 80
TABLE OF CONTENTS DRILLING JARS
• • • • •
BASIC JAR OPERATIONS........................................................ PUMP OPEN FORCE .......... ................................... ................. COCKING I TRIPPING THE JAR ............................................ DRILLING ACCELERATOR .................................................... JAR RULES I PLACEMENT GUIDELINES ..............................
•
PRIMARY WELL CONTROL .......... ......... .... .... ........................ .. 91
•
•
SWAB I SURGE PRESSURE ................................. .................. 92 SECONDARY WELL CONTROL .... .. .... .. ... .... .... .... ................... 95 KICK DETECTION TEAM . ........ ............ ...... .•. . .......................... 97 TERTIARY WELL CONTROL .................................................. 111 OBM KICK DETECTION I GAS BEHAVIOR ............................ 115
•
WELL CONTROL KILL SHEET ................................................ 117
•
CEMENTING CONSIDERATIONS ........................................... 119 STANDARD EQUIPMENT................................................. ........ 121
• • •
•
• • • •
81 82 83 86 87
EQUIPMENT I WELLBORE PREPARATIONS ........................ 122 CASING PRE JOB CHECKLIST ........................ ................... 125 RUNNING CASING GUIDELINES ........................................... 126 CEMENTING PRE JOB CHECKLIST ...................................... 127
•
TROUBLE SHOOTING CEMENTING PROBLEMS ................
• • •
HORIZONTAL WELL PROFILES .................. ........................... 132
WHY DRILL HORIZONTAL WELLS ......................................... 131 HORIZONTAL DRILLING BHA ..................•.............................. 133
• •
HORIZONTAL WELL CONTROL KILL SHEET ........................ 136
•
DRILLER HANDOVER NOTES ................................................ 138
•
SHAKER HANDOVER NOTES ................................................ 139
•
TIGHT HOLE I STUCK PIPE REPORT FORM ......................... 140
•
LOST CIRCULATION REPORT FORM .................................... 141
•
EQUIPMENT SELECTION /INSPECTION FORM .................. 142
•
DOWN HOLE TOOL FAILURE REPORT FORM ........ .............. 143
•
DRILL STRING FAILURE REPORT FORM ............................. 144
•
WELL CONTROL REPORT FORM ......................................... 145
HORIZONTAL WELL PLANNING ............................................ 134
TEAM BUILDING PRINCIPLES TEAMS
WHAT ARE TEAMS •
Two or more people worl
•
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 experienoe
•
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 TEAMS DO •
IMPROVE WORK QUALITY • More expertise/skills are available
•
FLEXIBLE - Respond quickly to change
•
CREATIVE. Conbnously improve wort< processes
•
DEVELOP AND IMPLEMENT ACTION PLANS -Better communications
•
REDUCE PROJECT COST
Page 1
WELL PLAN
An extensive depression in the earth~s surface An estimated 90% of the wortds drilllngs occurs In offshore and inland basins
A laterally continuous sequence of sediments that is recognizably distinct and mappable
Land mass elevated above sea level Is weathered and broken down to small fragments (clastics): Mechanically by water, wind and temperature Chemically by soluble minerals dissolving into the water
Rock fragments (sand. silt. clay) and dissolved chemical compounds (silicates, calcite, iron, etc.) are transported to the basin by gravity, flowing water and wind The fragments are swept into the basin Where they settle to the ftOOf of the basin and form water saturated beds or sand and clay
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 is squeezed out. the dissolved chemical compounds left cements the fragments together to form sedimentary rock
Page 2
WELL PLAN - -
--
CLAYSTONE & SHALE
MARL
------
Lesslhan 4 microns
-------
Rocl
Rocks formed from an accumulation of clay minerals and calcite (calcium carbonate)
Less than 4 microns
Mrl
BASIC GEOLOGY -
SILTSTONE
SLst
4to60 microns
SANDSTONE
Sst
60 llliCtOI\S to2mm
Sandstone comp
CONGLOMERATE
Cgl
Greater than 2mm
Rocks formed from an accumulation of primarily granule. pebble and boulder size particles
LIMESTONE
Ls
Rocks formed from an accumulation of mineral grains (quartz)
Rocks formed from large deposijs of primarily calcite (calcium carbonate) and dolomite (calcium magnesium) Chemical Rocks
DOLOMITE& CHALK
Comp
CHERT
Gypsum& Anhydrite
Rocks composed of minerals that p
SALT
Sa
BASEM ENT
Bm Rock fonned from the cooling of molten magma
Igneous rock VOLCANICS
Vole
FAULT
FH
A fracture in the rock caused by natural forces resulting in failure and displacement of the formation along the fault plane
OIL
0
L•quid hydrocarbon (5.0 to 7.1 ppg)
GAS
G
Native formation
Gaseous hydrocarbon (2 3 ppg average)
Aulds
water (8.3 to 11 .7 ppg)
WATER
-~
---
-
-
Pagel
-- - - - - -
-
------
BASIC GEOLOGY
WELL PLAN
TYPICAL POROSITY REDUCTION BY SEDIMENT COMPACTION AND CEMENTATION
0
/
NOTE: Deviations rrom the
/
, average porosity can occur
25~~/-L~----~~·'=·~~=~~~====r===~ 0
20
30
POROSITY%
The ability of a rock to flow fluids measured in units of darcies A rock that is porous does not indicate that it is permeable (i.e .• shale with 10% porosity may exhibit only micro permeability. 1o-6 to 1()·12 Clarey) TYPICAL PERMEABILITY REDUCTION BY SEDIMENT COMPACTION AND CEMENTATION 0
..
PERMEABILITY (Oarcies)
Page4
0
WELL PLAN
BASIC GEOLOGY
A force Imposed to the rocK matrix measured in pounds of force per square inch of area (psi)
Natural sources of rock stress originate from overburden stress. tectonic stress and formation nuld pressure The stress produced by lhe combined weight of the rocKs and formation fluids overlaying a depth of interest
TYPICAL OVERBURDEN STRESS VERSUS DEPTH
.,
·,.L--"'·""- -,,..,--,.--'"""....l..--:. OVERBURDEN STRESS ppg
The stress produced by lateral (side to side) forces in the formation Tectonic stresses are usually very high in mountainous regions
SIDE VIEW
Page 5
WELL PLAN
BASIC GEOLOGY ---
-
--
SOFT (Ductile) SHALE HARD (Brittle)
Generally occurs in deeper depth (10,000' +) Hard and britUe due to low water content Fracture pressure higher than injection pressure Brittle texture prevents fracture from "healing" Associated with hole pack-off/bridge Generally occurs in the shallower depth(< 5,000') High porosity (25% +) High permeability (2 darcies +) Associated with lost circulation, hole wash-out, hole pack-off
CON· SOUDATED
SOFT LIMESTONE/ DOLOMITE
(Chalk)
HARD (Brittle)
Generally occurs In mid to deep depths (4000' +) Porosity range (25% • 1%) Permeability range (2 darcies • 10 milidarcles) Associated with differential sticking, underguage hole Low compressive strength High porosity(+/- 40%) Permeability range (2 darcies- 10 milidarcies) \Mil dissolve In fresh water muds High compressive strength, usually fractured High porosity (20 - 40%). High permeability lost Associated with
Page6
differential
WELL PLAN
BASIC GEOLOGY
..
14-....:...--...L , IUIIHOfUIIAL,
•\
\
• •
- ~-----~·~---~-~
....... .... . , . .. ..
.
FORMATlOH PMAUM (10M IMJ) _,,,
~
··
·
··
·
·
· -~
·
pore fluid Is squeezed out of the ahele to the adJacent
Formation prossijre lesslhan the normal pressijre expected for the depth of interest Lower-than-normal formation pressijre may exist in offshore basins dije to production depletion, however. narumlly occurring subnormal pressure Is rare. In Inland basins. native subnormal pressure is a common occurrence -
- - - - - -- - - Page7
-
-
-
BASIC GEOLOGY
WELL PLAN
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
PageS
WELL PLAN
FUNCTIONS:
*
Drive or Structural Casing
.....
PROVIDE HYDRAIAJC WGRflY
. cmtacloo
*
PROTECTTHEWELLBORE • High f01111111on ,_,. • fli~Kku
·. ·.:·:.··..-.:··..··..-.:··..
Liner Tie Back - -----;:,.,..::,-,...,"::r Casing .........
... ...... . .. .... ..... . .. ..
PROTECT T1tE fORMATION
'
. .·....· ··...·.'
•'
'
·.
, •.
' lnc-Ciblt WtUboft flllds
·:. Production liner or Casing
• l'loduction Zoot llolllioo --~.;;.__-:..-..-,.
Page9
CASING PROGRAM
WELL PLAN
Shoe suength must support the hydrostatic. circulating and surge pressures and PfOVide a sufficient kick tolerance for well control safety In some instances. the only solution to a drilling problem may be to run casing before the planned shoe depth is reached. This could be the next planned casing string or a contingency liner Casing may be set before or deeper than its planned depth to protect
potential production zones Consolidated. Naturally cemented rock to avoid wash out and/or hole collapse during cementing As homogeneous as possible. Interbedded layers of d illerent formation types weaken the rock and introduce the possibility of permeability
fmpennuble. Water loss from the cement slurry can nash·setting of the cement before it is in place
resu ~
in
If permeability Is present, the tme leak·off pressure or the wellbore is difficult to establish
Lowest Rock Strength: Initial fracture gradient assumptions are based on the weakest rock type Clean shale is the ideal casing seat formation. tn the field, however, the formation selected for the seat Is usually the best compromise between the Ideal and what is possible
DATA:
FUNCTIONS:
PIPE SIZES
• Prevent Rig FOundation Wa•hout
9-6/8"- 38"
• Recycling ~oturn• • Olverter ayatem
DRIVE PIPE (Ortven to A:efusal)
• Vertleal P ilot STRUCTURAL CASING (Orill.cl •nd Cfl!"'ent~MJ)
• Structural Support conductor caalng
SHUT·IN NOT RECOMM£NOEO
Page 10
WELL PLAN
Planned sening 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
The casing is pressure tested and the shoe Is tested to a ma~imum anticipated pressure or to leak-off
Page 11
WELL PLAN
DATA: PIPE SIZE
FUNCTIONS: • PROVIDE WE.LL CONTROL CAPABILITY
5" ·ll-311"
• SOLUTION FOR
DRILliNG PROBLEMS: • CEIIENTED BACK
• lolt ~ulatloo
TO PREDETERIIINED DEPTII • Oillt,..,tlat Sticking
• CASING PRESSURE
TESTED
• PROTECT FORMATIONS: ' LowiHigh Wtllbolt
Prttsure ' lncompotlblt Wtllbore Fluids
• SHOE PRESSURE TESTED
• Productloo Zone ls4latlon
• SHUT~N RECOMMENDED (Stlln P*'ure Trensition Shalt!
WELL PLAN
CASING PROGRAM
Planned setting depth determined by minimum desired kick tolerance, anticipated hole instability, lost circulation problems or protecting production zones If the liner is contingent on drilling problems, occurrence of the problem determines the setting depth
FUNCTIONS:
DATA:
' PROVIDE WE.L.L CONTROL CAPABIUTY '
PIPE SIZE • SOLUTION FOR SPECIFIC DRILLING PROBLEMS:
s· -t t-314"
.
.
• LO$t circulation
CEMENTED BACK TO UNER HANGER
• Formation Instability ' Dlfforentlal Slicking
• Low/High Wellbore Pressure
' LINER PRESSURE TESTED
• Incompatible Wollbore Fluids • Production Zone Isolation
SHUT~N RECOMMENDED
The liner Is pressure tested and the shoe and liner top tested to a maximum anticipated pressure leak-off Page 13
or to
WELL PLAN
Planned setting depth determined by total depth of the well (TO)
FUNCTIONS:
DATA:
• PROVIDE WELL CONTROL CAPABILITY
PIPE SIZE
s· .9-518" • PROVIDE A STABLE WELLBORE: • CEMENTED BACK TO PREDETERMINED
• WeiiTosting
DEPTH • Production Operations
• UNER I CASING I TIE· BACK CASING PRESSURE TESTED
• Protects Intermediate casings
' PRODUCTION ZONE ISOLATION: ' Selective Testing • Dual Completions
Page 14
WELL PLAN
DRILLING FLUIDS
A ftuid used to perform various functions during a drilling operation
.
.
. ~ WELL CONTROL HOLE STABILITY
HOLE CLEANING
TRANSMIT HYDRAULIC HORSEPOWER TO BIT FORMATION EVALUATION
.,.. : "
' .. .!.!;~~~0 £1~·-•. ~.-;'t\"1",..,_.... ~·~· f!,~.:-.
.
....
.
~\~ '""·"''f'C.:"•dYJ..,.,;.,.--~
' t ....
•
{ ¥~~-
~ ...... ·,
Fluid weight Chemically- Mud Inhibition Mechanically - Fluid Weight Yield Point (YP) Gel Strength Mud weight
,,
'
'
. ,
i~t-i-
Primary control or formation fluid flow into the well bore Minimize formation reaction Prevents hole cave-in/collapse Suspend and carry cuttings/cavings from the wellbore and release the solids at surface
Base fluid of the mud
Remove cuttings from below bit race to improve penetration rate
Mud system type and properties
Gather and interpret data Provide early wamlng signs of problems
DRY AIR /GAS MIST FOAM AERATED MUD
Drilling hard dry formations Drilling lost circulation zone
NATIVE GEL BENTONITE BENTONITE/CHEMICAL
Low cost spud mud Non-weighted system Base lor more sophisticated systems.
Most versatile system Products readily available
LIGNITE/ LIGNOSULFONATE (DISPERSED)
Filtration control
Easily maintained Reduced penetration rate
Tolerance to contaminants Applicable at all mud weights
INHIBITIVE (SALTS) POLYMERS
Drilling water sensitive shales
DIESEL OIL SYNTHETIC OIL
Drilling water sensitive shales Drilling water soluble formations ·Reduce stuck pipe potential Corrosive environment
High bottom hole temperature
Page 15
lnaease penetration rate
Minimum !ormation damage Continuous gas/oil detection
Basic system
chemical reaction or shales Improved penettatlon rate
Completely inhibited system Improved penetration rate
Formation stability Torque & drag reduction Environmental concerns High cost Logging! cementing concerns
DRILLING FLUIDS
WELL PLAN
The selected drilling fluid is usually the best compromise of the available choices
Seismic data Offset data Field experience Mud company records
An "overl
ENVIRONMENTAL
Regulatory requirements
May lim~ the choice of mud systems
WELL CONTROL REQUIREMENTS
Seismic data evaluations Offset well data Foeld experience Mud company records
The mud system must be capable of minimum to maximum mud weight requirements
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)
WELL TYPE (Exploratory I Development)
HOLE STABILITY Chemical/ Mechanical
The optimum mud system Is selected on development wells
The mud system must be capable of minimum to maximum mud weight requirements TEMPERATURE/ CHEMICAL STABILITY OF THE MUD
Offset well data Foeld experience Mud company records
The mud system must tolerate formation temperatures w1thout chemical breakdown Must tolerate contamination from formation fluids. minerals and solids
OPTIMUM DRILLING AND ECONOMIC PERFORMANCE
Offset welt data Field experience Mud company records Bit company records
Offset welt data BASE FLUID I MUD PRODUCT AVAILABILITY Mud company records RIG EQUIPMENT
Contractor Inventory Field experience
Page16
The mud system should provide an acceptable penetration rate w~h formation damage at the lowest cost
May limit the choice of mud systems in remote areas May lim~ the choice of mud systems in remote areas
WEL!.PLAN
DRILLING FLUIDS
Active solids • Clays
DRILL SOLIDS
Inactive solids - Silt. sand. limestone. chert, etc.
Sodium chloride. NaCI Potassium chloride, KCI Calcium chloride. cac1 2 Magnesium chloride, MgCI 2 Anhydrite. CaS04
EVAPORITE SALTS
Mixed satts at various concentrations
WATER FLOWS
Carbon dioxide, co2 Hydrogen sulfide,
ACID GASES
¥
Light or heavy oils Ugnne Coal
HYDROCARBONS
Degradation of mud products
TEMPERATURE
~'-"•~~,.~~::or,:·· .'··C• ·'?iT'?'" !>·~~-""''"·•r '')<'~-·~ ~
£"'... ·:
~·
..: '
•r, ./-•
'_:. ..:.
•
::.........._~;t.__!l~~·
:, . : ,'- ~~
COARSE
Between 250 and 2,000 microns
MEDIUM
Between 74 and 250 microns
FINE
Between 44 and 7 4 microns
ULTRA-FINE
Between 2 and 44 microns
COLLOIDAL
Less than 2 microns
',.~,_,,-~~'"··~.,-p~~~~
•,_.;·~;_·.
•
·t"-''';"11111{ . r"'
Greater than 2 000 microns
INTERMEDIATE
,.-:~«'
,;..__·-· .• '··'. : ....~
-~~· j'• ,.,.,.,,.,_ '•';'1·•·.•'-<'V="-· -jlii,.~ •• =- •.•• ' • J. .... ,,ll.t;.e1:
·..,:. :-. ...::~..:.·,:~.·~:-
·r, •,;· --~ < '·
~t;-~h --"
'il...''o.'' ....__..
•"0W,
--~-,
. , .........
-~.J.J.»,~;~;.~' ..::: .
._.,,.
.. • ·r·~~~--.- •. -~·--~ _•...J.i •.-L- _ _.:....~--
SHALE SHAKERS
~\lif;p ·,I ,,1
.
•
..,_ ~·--~~ • ',d." -:
.:.r
Down to 150 microns with 200 mesh screens
DESANDER
Down to 50 to 70 miaons (cone size dependent)
DESILTER
Down to 20 to 40 miaons (cone size dependent)
MUD C LEANER CENTRIFUGE
Down to 74 microns Colloidal solids up to 5 microns
Page 17
'··~.11
--~
.'.A...J-,
WELL PLAN
~ - -'
INCREASE
Crill solids Increase, Heavy spot from barite sag, Over treatment during weight-up
DECREASE
Formation flutd influx, Ught spot from barite sag. Excessive water additions
INCREASE
Reactive shale dnlled. Crill solids increase. low water contenL Calcium contamination from cement, Anhydrite formation drilled
DECREASE
Formabon water ...nux. Excessive water content
INCREASE
Unconsolidated sand drilled, Drill sollds increase. low water content
MUD WEIGHT
FUNNEL VISCOSITY
PLASTIC VISCOSITY
DECREASE
Formation water Influx. Excessive water additions. Solids content decrease
INCREASE
Reactive shale drilled, Anhydrite formation drilled. Low water content, Calcium contamination from cement.
DECREASE
Formation water influx, Excessive water add~ions. Oeaease in low grav~ solids. Additions of chemical th1Mers
YIELD POINT
INCREASE GEL STRENGTH
API/ HPHT FLUID LOSS
pH
Formation water influx, Excessive water
DECREASE
additions, Additions of chemical thinners
INCREASE
Low gravity sOlids Increase. Flocculation from cement, chloride. calcium contamination. Low gel content
DECREASE
Mud treatment taking affect
INCREASE
Addition of pH oontrol add~ives, Calcium contamination
DECREASE
Addotion of mud products, Anhydrite formation drilled
INCREASE
Sa~ formation is drilled. Pressure transition shale is drilled, Formation water influx
CHLORIDE
TOTAL HARDNESS CATION EXCHANGE CAPACITY (CEC)
Reactive shale dnlled, Low watet content, CalCium contamonatoon lrom cement. or anhydrite formation drilled
DECREASE
Water addrtions
INCREASE
Salt or calcium formation is drined, Formation water ...nux
DECREASE
Addotion of lresh water, Chemical add~ion
INCREASE
Reactive shale Is drilled, Addition of bentonite
DECREASE
Water additions. Solids removal equipment
Page 18
-
WELL PLAN
Page 19
DRILLING FLUIDS
WELL PLAN
HYDRAULICS PLANNING
..
\...
'lp>,.............
.
~ ·-
-
.
)'-,;,~
'
. -.-.~
-
..
•. ·.• .
-·..:i·-*
'
.&<=-·
-
•
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 clean the bit and well bore with minimum horsepower
,_,...,r • '
. ..
-
'·
~.,
•
MAXIMIZE RATE OF PENETRATION (ROP) MAXIMIZE HOLE CLEANING
. •
Lost Circulation; Differential Sticl
•
In soft, unconsolidated formations. limit flow rate to mini mize turbulence in the annulus if hole wash-out is a problem
•
Larger jet sizes may be required If there is potential for lost circulation
HYDRAULIC EROSION
..rr-
'
In small a.nd/or deep holes. limit flow rate to minimize annulus
friction pressure and reduce the potential for.
•
.
In soft formations and high angfe holes, maximize ftow rate
for hole cleaning.
ANNULUS FRICTION PRESSURE
BIT PLUGGING
In medium to hard formations, ma.ximize hydraulic horsepower to increase penetration rate
"
•. ,
•
. PUMP PRESSURE I VOLUME OUTPUT
DEPTH I HOLE SIZE I MUD TYPE
DRILL STRING ID, OD, LENGTH
MUD WEIGHT I RHEOLOGY
DOWN HOLE EQUIPMENT RESTRICTIONS
ANNULUS FRICTION PRESSURE
BIT TYPE I JETS
HOLE PROBLEM POTENTIAL
Page 20
WELL PLAN
HYDRAULICS PLANNING
•
Do not violate the flow rate rule to get more horsepower, jet velocity
•
Too low a How rate wilt "ball" the b~ and reduce effective hole cleaning
•
Too high a flow rate increases ECD and erodes soft or unconsolidatecr 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 cliameter
•
Hydrolic horsepower is basecl on hole size/ROP. l arge bits require more HHP!In'
•
Fast drilling requires the maximum HHP/In~ even above 5 HHP/trl
•
Maximum HHP!In' should be consiclered when pump horsepower is available
•
Do not waste fuel a ncr wear on tile pumps ~h excessive pressure
•
Many rigs do not have enough horsepower to provide the recommended HHP/In
•
Nozzle velocity (ftlsec) • The velocity of the fluid exiting the bit jets
•
35% to 50% of pump pressure is lost through the clrill string a ncr annulus. Hydraulic calculations are requlreclto determine these losses
•
If the total of drill string and annular pressure loss is greater than 50% of the available pump pressure. Jet Velocity optimization is required. However, do not operate below 30 GPM per inch of bit ella meter
•
Impact Force • The product of fluicl j et velocity and fluid weight. Impact is the force the drilling nuicl exerts to the formation toasslst bottom hole cleaning
•
Jet velocity will influence chip·holcl·down and penetration rate
•
Do not operate with a jet veloc~y below 250 ftlsec
•
For small holes (9· 112" and smaller) and slow drlllin, 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 j ets (same total flow area, TFA)
•
tr a long hole section is plannecl for the next ~. consider running 3 j ets and dropping a diverting ball in the lower part of the hole section to maintain jet velocity
•
Asymetrical jets are often run to improve penetration rate versus using two jets
2
Page 21
STUCK PIPE
HOLE PROBLEMS
Planned operations are suspended when down hole force(s) prevent pulling l.he siring oul oflhe hole Down hole force( a) reelncl siring movement above normal operaling condilions (a usual warning indicator of a stuck pipe evenl)
MECHANISMS ···oro;·~
' .'
.....
-·-~;-.
·-- ~ 7_~-i~~~r ...
SETTLED CUTIINGS
--~
DIFFERENTIAL FORCE
STIFF ASSEMBLY
SHALE INSTABILITY
KEY SEAT
UNCONSOLIDATED FORMATIONS
MICRO DOGLEGS
FRACTURED FORMATIONS
LEDGES
CEMENT RELATED
MOBILE FORMATIONS
JUNK
UNDERGAUGE HOLE
C AUSES
HOLE PACK-OFF: Foonafion solids (cultlngs. cavings) sellle around lhe dnll s1nng and pack oil lhe annulus resulbng on sluck pipe
BRIDGE:
Medium 10 large poeces of hard formation. cement or junk falls inlo the wellbore and jams the drill string resulting in stuck pipe
'-~··~--·T~~~~' •, • '.;11-....___.,:... • •.rJ__ ....._:--.-
Wk
• ..,.
; -"
.
SETTLED CUTTINGS
SHALE INSTABILITY
SHALE INSTABILITY
REACTIVE SHALE GEO-PRESSURED SHALE HYDRO-PRESSURED SHALE OVER BURDEN STRESS TECTONIC STRESS
OVER BURDEN STRESS TECTONIC STRESS
UNCONSOLIDATED FORMATION S
UNCONSOLIDATED FORMATIONS
FRACTU RED FORMATIO N S
FRACTURED FORM ATIONS
SOFT CEMENT
C EM ENT BLOCKS
JUNK
Page 22
-
HOLE PACK.QFF
STUCK PIPE
HOLE PROBLEMS
CIRC ULATING TIME
DRILLED CUTTINGS ARE NOT TRANSPORTED OUT OF THE HOLE DUE TO LOW ANNULAR VELOCITY AND/OR POOR MUD PROPERTIES WHEN CIRCULATION IS STOPPED. THE CUTTINGS FALL BACK DOWN THE HOLE AND PACK.OFF THE DRILL STRING
HIGH ROP, LOW PUMP RATE, LlffiE TO NO CIRCULATING TIME AT CONNECTIONS TORQUE. DRAG AND PUMP PRESSURE INCREASE OVER PULL OFF SLIPS, PUMP SURGE TO BREAK CIRCULATION FILL ON BOTTOM
LIKELY TO OCCUR ON CONNECTIONS, POSSIBLE DURI NG TRIP CIRCULATION RESTRICTED OR IMPOSSIBLE FIRST A CTION:
APPLY LOW PUMP PRESSURE (200 - 400 psi) APPLY TORQUE AND JAR DOWN WITH MAXIMUM TRIP LOAD CIRCULATE CLEAN TO AVOID RECUR.RENCE PREVENTTVE ACnON:
CONTROL ROP, MAXIMIZE ANNULAR VELOCITY MAINTAIN SUFFICIENT GEL STRENGTH AND YP CIRCULATE 5 TO 10 MINUTES BEFORE CONNECTIONS CIRCULATE HOLE CLEAN BEFORE POOH
Page 23
STUCK PIPE
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° DRILLING WITH A DOWN HOLE MOTOR HIGH ROP. LOW PUMP RATE. INCREASE TORQUE & DRAG, INCREASING PUMP PRESSURE
INDICATIONS: LIKELY TO OCCUR WHILE POOH, POSSIBLE WHILE DRILLING INCREASE OVERPULL ON TRIPS CIRCULATING PRESSURE RESTRICTED OR IMPOSSIBLE
FIRST A CnON : APPLY LOW PUMP PRESSURE (100- 400 psi) JAR DOWN WITH MAXIMUM TRIP LOAD, APPLY TORQUE W ITH CAUTION TO AVOID RECURRENCE
PREVENTIVE A CTION: RECORD TREND INDICATORS FOR INADEQUATE HOLE CLEANING CONTROL ROP. MAINTAIN MUD PROPERTIES, CIRCULATE AT MAXIMUM RATE, MAXIMIZE STRING ROTATION CIRCULATE HOLE CLEAN BEFORE POOH, ESTABLISH AN OVERPULL LIMIT
Page 24
STUCK PIPE
HOLE PACK-OFF
TORQUE
DRAG DRILLING
Increasing, erratic
PRESSURE
HOLE PROBLEMS
OTHER
Increasing
Pressure surges Gradual decrease in ROP
Surge to start
Back pressure before breaking connection Back now
Increasing, erratic
CONNECTION
Overpull off slips
TRIPPING OUT TRIPPING IN BACK REAMING
Increasing, erratic Overpull off slips
Swabbing
Increasing set down weight Overpull off slips
Begins with BHA below depths ol35° hole angle
PUMPING OUT E2_:
i~--ifJ~'!
SHAKER TRENDS LOGGER TRENDS MUD TRENDS
circulations
Increasing, erratic
Overpull off slips Erratic overpull Overpull off slips Increasing, erratic
.
Increasing
Surge to start circulation String pistoning Loss of ftuid possible
Increasing
Surge to start circulation String pistoning, Loss of Ouid possible
-ti'EMII!IDIQ4110NI
Low cuttings return rate tor penetration rate, Erratic cuttings returns, No cuttings retum. High cuttings retum on fine shaker screen and desilter I mud cleaner Rounded, reground cuttings
Increasing plastic viscosity and yield point. Increase in low gravity s<>lids, Possible
mud weight increase
PREVEN1IVE ACTION •
Maintain the required mud properties
•
Circulate at maximum recommended GPM for hole size
•
Place more emphases o n annular vetoc~y when designing the hyc!raulics for 12-1 14" and larger hole sizes. Consider using a riser booster line when drilling 8-112" and smaller hole sizes
• Do not allow I he 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 clown hole motor
•
Wipe the hole at full circulating rate as low as possible (5 - 10 min) before connections. Rotate at maximum RPM when possible
•
Maximize string motion when circulating the hole clean. Use maximum practical RPM. raise the drill string slowly (5 minl std) and slack-off at a safe but fast rate (1 minlstd)
•
Consider pumping high-vis sweeps in low angle wells (<35''). Consider low-vis I high-vis sweeps in higher angle wells (>3sj
0
DO NOT STOP CIRCUlATING UNTIL ALL SWEEPS RETURN
•
Circulate until the hole is clean. If the last sweep brings up excessive amounts of cutlings, continue with hole cleaning operations, Several circulations may be necessary
Page 25
STUCK PIPE
HOLE PROBLEMS
HOLE PACK-OFF
MINIMUMGPM
'7i!T
r-;;.
~ ~t-
26"
HOLE SIZE
•
17-1/2"- 16"
t.!i 12-1/4"
II~!,..
-
' 'I
I
.... ~ 't-: -·
I
8-1/2"
ANGLE INTERVAL 0°- 35'
700 GPM
500GPM
400 GPM
300GPM
35'- 55'
1250 GPM
950GPM
650 GPM
450GPM
1100GPM
750 GPM
500GPM
55'+
Minimum flow rate (GPM) for any gwen hole SIZe and angle Is greatly dependent on mud weight. mud rheology and annulus geometry Maximum recommended flowrate is SO GPM per inch of bit diameter MAXIMUMROP
r·A'OPI
HOLE SIZE
VERSUS HOLE SIZE AND-. OLE 17-1/2"-16"
26''
8-1/2"
12-1/4"
ANGLE INTERVAL 0°- 35 °
60
110
155
35"- 55°
40
75
85
60
75
55°+
240
-
125 100
Penetration rate guodelines are based on adequate mud properties
MINIMUM STROKES
~ CUL
,s·
S.FACl OR fCSF\ TO CLEAN HOLE
26"
17-1/2"- 16"
0°-35 °
2
17
35~ 55 °
2.5
25
HOLE SIZE ANGLE INTERVAL
3
55°+
8-1/2"
12-1/4"
1.4
-'--
1-
1.4
1.8
1.6
2
1.7
PROCEDURE: 1. Separate the wellbore into sectoons by hole angle from intetvals above. 2. Multiply each hole section length (Sect. lth) by CSF and total the adjusted measured depth (MD). Adjusted MD= (Sect. Llh X CSF) +(Sect Lth X CSF) +(Sec/. Lth X CSF) 3. Calculate the minimum circulating strokes to clean the hate.
M1mmum C1rc Stks
=
Total Ad£usted MD x Bottoms-Ue, Stks ~easurea lJepl1i
Page 26
STUCK PIPE
HOLE PACK-OFF
ADJUSTED MD
= (SECT LTH ~ CSF) + (SECT LTH x CSF) +(SECT LTH x CSF) = (4500x 1.4) + (2000 x 1.8) + (6500x2) = 6300 + 3600 + 13,000 22.900 TOTAL ADJUSTED MD
MIN CIR STKS
= TOTAL ADJUSTED MD x BOTTOMS-UP STKS * MEASURED DEPTH 22900 X 15 000 13,000
=
26.423 STROKE$
Page 27
HOLE PROBLEMS
STUCK PIPE
HOLE PACK-OFF
Maintain sufficient mud weight to stabilize the wellbore as hole angle and/or formation pressure
tncreases Use proper low-End-Rheology for hole siZe and angle to maxim1ze hole cleaning Circulate at maximum rate for hole size and hole angle Limit the ROP to the maximum rewmmended for hole size and hole angle Back ream each stand (or 1/2 stand) drilled with a down-hole motor 0
Rotate at high RPM (160+). Raise the dnll string slowly (i.e., 5 min/stand). l ower the drill string at a safe but fast rate (i.e ., 1 min/stand)
• Continue back reaming if hole conditions dictate • Consider a wiper trip after drilling a long section with a down hole motOf to mechanically agitate and remove cuHings bed Pump a sweep (p1ll) if hole conditions do not improve. Consider low-vis I high-density tandem sweeps. Optimize sweep type. volume and frequency pumped
Consider reducing ROP or stop dnlling and circulate unbl hole conditions improve
Start and stop drill stnng slowly. Ensure adequate back reaming at full circulation rate prior to
connect1ons Prepare crew and equipment to minim1ze connection time Rewrd free rotating weight, pick-up weight. slack-off weight. off-boHom torque. and circulating pressure for trend indications of inadequate hole cleaning Pull th~ slips and slovvty rotate the drill string first, then increase pump speed slowly. Carefully lower the
drill string to bottom
C11culate 1 to 3 joints off bottom while c leaning the hole to avoid dropping bottom hole angle. Consider sweeps (pills) to ai d hole cleaning Rotate at high RPM (160+) while cleaning the hole. Raise the drill sUing slowly (o.e .• 5 min/stand). lower the drill sUing at a safe but fast rate (i.e .. 1 min/stand)
Ensure recommended min1mum circulat1on strokes for-hole size and angle are pumped, 2 to 4 times normal bottoms.up may be required Circulate until the shakers are dean Consider pumping a sweep (pill) to determine if additional circulation time is required Inform the Droller ol the measured depth and stand count when the top of the BHA reaches the deepest anticipated cuttings bed Maximum cuttings bed thickness is hkely between 45• and 6 5' hole angle Determine a n overpull tlm1t pnor to pulling out of the hole (the lesser of 112 BHA weight or 30.000 lbs)
If overpull limit occurs. run in 1 stand and repeat hole cleaning g uidelines from present bit depth. When the shakers are clean. continue pulling out of the hole. If the overpulllimit is again reached. repeat procedure CAUTIOUSLY BACKREAM OR PUMP-OUT STANDS WHEN A CUTTINGS B ED IS PRESENT!!
Be patient. several hole cteamng cycles may be required to safely pull the drill sting out of the hole Record depths and stand count of high pick-up weights during the IJip. Compare these to the drilling pick-up weights for the same depths to determine value of overpull
Page 28
STUCK PIPE
H OLE PACK-OFF
GEO-PRESSURED SHALE REACTIVE SHALE
HOLE PROBLEM S
HYDRO--PRESSURED SHALE
OVERBURDEN STRESS
TECTONIC STRESS
WATER SENSITIVE SHALE DRILLED WITH UTILE OR NO MUD INHIBITION SHALE ABSORBS WATER AND SWELLS INTO THE WELLBORE REACTION IS TIME DEPENDENT
FUNNEL VISCOSITY, PV. YP. CEC INCREASE TORQUE & DRAG INCREASE PUMP PRESSURE INCREASE CLAY BALLS AND/OR SOFT "MUSHY" CUTIINGS AT SHAKER
OAY!I EXI'OS~IRE 1 OVER PULL & SWABBING BHA BALLING (MUD RINGS)
GENERALLY OCCURS WHILE POOH. POSSIBLE WHILE DRILLING CIRCULATION IMPOSSIBLE OR HIGHLY RESTRICTED
..
FIRST ACTION: APPLY LOW PUMP PRESSURE (200 • 400 PSI) IF POOH. TORQUE UP A ND JAR DOWN WITH MAXIMUM TRIP LOAD
EXPOSURE I IF RIH, JAR UP WITH MAXIMUM TRIP LOAD, DO NOT APPLY TORQUE
PREVENTIVE ACTION: USE AN INHIBITED MUD MAINTAIN MUD PROPERTIES PLAN WIPER TRIPS M INIMIZE HOLE EXPOSURE TIME
. Page 29
'
STUCK PIPE
HOLE PROBLEMS
.....,.
DRILLER
CONNECTION TRIPPING OUT TRIPPING IN BACK REAMING PUMPING OUT
_,_
SHAKER TRENDS LOGGER TRE NDS MUD TRE NDS
I OF.
TORQUE
DRAG
DRILLING
HOLE PACK-OFF
Increasing Smooth
Increasing, Smooth
PRESSURE Increasing
Surge to start circulation
Overpull off slips
OTHER Pressure surges Gradual decrease in ROP Mud loss possible Back pressure before connection Back flow
Increasing, Smooth Overpull off slips
Swabbing
Increasing set down
Begins at depth of problem formation Mud loss possible
weight Overpull off slips Increasing, Smooth
Overpull off slips
Increasing, Smooth Overpull off slips
:
.
Increasing
Surge to start circulation String plstoning Loss of mud
Increasing
Surge to start circulation String pistoning, l oss of mud
RIG TEAM INDICATIONa .
Soft clay balls. Wet "mushy" clay (gumbo). Flow line plugging
Large quanty of hydrated shale cuttings. High value on shale swelling test High funnel vis. & YP. Increasing PV. tow gravity solids & CEC. Possible mud weight increase. Low inhibitor content
~-
-
PREVEN'fiVE ACTIQN
• Addition of various salts (potassium, sodium, calcium, etc.) to reduce the chemical attraction of water to the shale • Addition of various encapsulating (coating) polymers to reduce water contact with the shale • Use of oil and synthetic base muds to exclude water contact with the shale • Minimize open hole time • Plan regular wiper I 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
DRILLING PRESSURED SHALE WITH INSUFFICIENT MUD WEIGHT. THE STRESSED SHALE FRACTURES AND CAVES INTO THE WELLBORE
SIGNS BEGIN TO OCCUR AS SHALE IS DRILLED MUD LOGGER TRENDS INDICATE INCREASING PORE PRESSURE ROP INCREASE WHEN FIRST DRILLED TORQUE INCREASE & DRAG ON CONNECTIONS HOLE FILL ON CONNECTIONS. BRIDGES ON TRIPS. SPLINTERY SHALE CAVING$ POSSIBLE BACKGROUND GAS INCREASE
cc.·.· ~'""""·~··"""'-'-1 LIKELY TO OCCUR WHILE TRIPPING. POSSIBLE
WHILE DRILLING COMPLETE PACK-OFF LIKELY. HOLE BRIDGING POSSIBLE CIRCULATION RESTRICTED OR IMPOSSIBLE
FIRST ACTION: APPLY LOW PUMP PRESSURE (200 • 400 psi) APPLY TORQUE. JAR DOWN W ITH MAXIMUM TRIP LOAD
ADJUST MUD WEIGHT BEFORE DRILLING KNOWN PRESSURED SHALE SLOWLY INCREASE MUD WEIGHT TO STABILIZE SHALE MINIMIZE SWAB I SURGE PRESSURES
Page 31
STUCK PIPE
HOLE PROBLEM S
HOLE PACK-OFF
• CAUSE: OVER TIME, SHALE PORE PRESSURE BECOMES CHARGED BY HYDROSTATIC OVER BALANCE DRILLSTRING MOTION AND WELL BORE 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
POSSIBLE WHILE DRILLING OR TRIPPING HOLE BRIDGING OR COMPLETE PACK-OFF POSSIBLE CIRCULATION RESTRICTED OR IMPOSSIBLE
APPLY LOW PUMP PRESSURE (200 • 400 psi) , APPLY TORQUE. JAR DOWN W!TH MAXIMUM TRIP LOAD ---~--~~
•
•
•
CIRCULATION AT MAXIMUM RATE ONCE • CIRCULATION IS ESTABLISHED
•
0
~-;----·--.-·~---.-- --~--
PREVENTIVE ACTION: USE OBM. SBM OR GLYCOL BASE MUD IF PROBLEM IS SUSPECTED IF A WEIGHT REDUCTION IS NECESSARY, REDUCE GRADUALLY OVER SEVERAL CIRCULATIONS MINIMIZE WELLBORE PRESSURE SURGES
•
0
0
•
Page 32
0
0
•
0
0
•
0
0
•
0
0
HOLE PACK-OFF
STUCK PIPE
HOLE PROBLEMS
MUD WEIGHT IS INSUFFICIENT TO SUPPORT THE OVER BURDEN MUD WEIGHT IS NOT ADJUSTED AS HOLE ANGLE INCREASES STRESSED SHALE FRACTURES AND FALLS INTO THE WELLBORE
HOLE CLEANING PROBLEMS INCREASE TORQUE & DRAG
CAN OCCUR WHILE DRILLING OR TRIPPING HOLE BRIDGING OR PACK-OFF POSSIBLE RESTRICTED CIRCULATION OR NO CIRCULATION POSSIBLE
APPLY LOW PUMP PRESSURE (200 - 400 psi) APPLY TORQUE, JAR DOWN WITH MAXIMUM TRIP LOAD
USE MUD WEIGHT NEEDED TO STABILIZE THE OVER BURDEN INCREASE MUD WEIGHT AS HOLE ANGLE INCREASES
Page 33
STUCK PIPE
HOLE PACK-OFF
HOLE PROBLEMS
CAUSE: NATURALLY OCCURRING LATERAL FORCES IN THE FORMATIONS STRESSED SHALE FRACTURES, FALLS INTO ---~-' THE WELLBORE AND JAMS THE DRILLSTRING •-~--. SANDSTONE SQUEEZES IN CAUSING UNDER
GAUGE HOLE
:.....;:--~ MOUNTAINOUS LOCATION
=·~:"J PROGNOSEO TECTONICS
e:!l1~1J;-:j.~ .:
,.:. ,.· ERRATIC TORQUE & DRAG · BLOCKY SHALE CAVINGS
PREVENTIVE ACTION: INCREASE MUD WEIGHT IF POSSIBLE CIRCULATE HIGH DENSITY SWEEPS MINIMIZE WELLBORE PRESSURE SURGES
Page 34
STUCK PIPE
HOLE PROBLEMS
~·;#
.
~~···_...I.
DRILLING CONNECTION TRIPPING OUT TRIPPING IN
lncreas1ng, errat1c
lncreas1ng,
Jl .. •
PRESSURE Increasing
erratic Surge to start circ ulation
Overpull off slips
Ia
•Jt
OTHER Increase ROP followed by gradual decrease. Pressure surges Hole fill
Increasing, erratic Overpull off slips
Swabbing
Increasing set down weight
Beg1ns at depth of problem formation Hole fill on bottom
BACK REAMING
Overpull off slips
PUMPING OUT
lncreasong, erratiC Overpull olf sl•ps
l
-.~I••·-
TORQUE
....._-1- --'D,_RAG
HOLE PACK -OFF
lncreas1ng.
-
Increasing
Surge to stan carculahon Stnng p1stoning Loss of ftuid possible
lncreasJng
Surge to start clfculatiOn String plstoning Loss of ftu•d poss•ble
erratiC
lUG TUMIMDICA110N8
I
SHAKER TRENDS
Large, spt1ntery or blocky shale cavings. Large volume of cavlngs
LOGGER TRENDS
Large quanty of slllntery or blocky cavings with striations. Poss1ble indications of increase in formation pressure Prognosed mechanically stressed shale
MUD TRENDS
Poss•ble st.ght •ncrease
.n mud we!Qht and plastic viscosity
-.
.
•
Consider offset well data and/or computer models Which simulate shale failure limit& when planning the mud weight tor each hole section
•
Mud weight increase with hole angle and 1VD 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 densrty for a g1ven depth is reached. Th1s w111 ma•nta1n an overbalance against hydrostatically sensitive shales
•
AVOID MUD WEIGHT REDUCTION after 1+ day exposure to hydrostatically senSitiVe shale If mud weight reduction is necessary, reduce the mud weight gradually over a bme frame equal to the tJme of exposure
•
Use the Shaker Handover Notes to determ•ne trends of cuttings volume, size and shape
•
Maintaan mud properties to ensure hole c:~aning
•
Use sweeps to help c lean the hole
•
Stop drilling until the hole Is circulated clean
•
MinlmlZe open hole exposure t1me
•
Plan contin en
to case-off the problem
Page 35
I
I
HOLE PROBLEMS
STUCK PIPE
HOLE PACK-OFF BRIDGE
LIITLE 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 S TRING
LIKELY TO OCCUR AS THE FORMATION IS DRILLED
INCREASE TORQUE & DRAG, PUMP PRESSURE FLUCTUATIONS HOLE FILL ON CONNECTIONS & TRIPS
GENERALLY OCCURS IN SURFACE HOLE CAN OCCUR W HI LE DRILLING OR TRIPPING SUDDEN PACK-OFF W ITHOUT WARNING CIRCULATION IMPOSSIBLE
• APPLY LOW PUMP PRESSURE (200 • 400 psi) - • JAR DOWN WITH MAXIMUM TRIP LOAD, APPLY TORQUE WITH CAUTION
PREVENTIVE A CTION: CONTROL FLUID LOSS TO PROVIDE A N ADEQUATE FILTER CAKE CONTROL DRILL SUSPECTED ZONE
SPOT A GEL PILL BEFORE POOH
Page 36
STUCK PIPE
HOLE PACK-OFF I BRIDGE
DRILLING CONNECTION TRIPPING OUT TRIPPING IN
Increasing. erratic
Increasing. erratic
HOLE PROBLEMS
Increasing
Surge to start
Overpull off slips
circulation Increasing, ettatic Overpull off slips weight
BACK REAMING
Overpull off slips
PUMPING OUT
IncreaSing, erratic
Increasing,
Increasing
Surge to start circulation Siring pistoning Loss of fluid possible
Increasing
Surge to start circulation String pistoning, Loss of fluid possible
erratic
Overpull off slips
RIG·TEAIIINDICATIOHI
_0
•
SHAKER TRENDS
Large volume of sand over shakers. Sand IJ'ap and desander overload.
LOGGER TRENDS
Large q uantity of sand in samples. Prognosed unconsolidated formation.
MUD TRENDS
Increase in mud weight and plastic viscosity. High % sand content
CTION •
Provide an effective filter cake lor the hydrostatic overbalance to "push againsr' and stabilize the formation
•
II possible, avoid excessive circulatmg 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 av01d 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 lor shaker, desilter. desander overtoads
•
Minimize seepage loss with fine lost circulation material through these intervals
Page 37
HOLE PROBLEMS
STUCK PIPE
HOLE PACK-OFF I BRIDGE
NATURALLY FRACTURED FORMATIONS PIECES OF FORMATION FALL INTO THE WELLBORE AND JAM THE DRILLSTRING
PROGNOSED FRACTURED LIMESTONE, SHALE AND/OR, FAULTS
MUD LOGGER FORMATION EVALUATION BLOCKY CAVINGS AT SHAKER HOLE FILL ON CONNECTIONS AND TRIPS
LIKELY DURING TRIPS, POSSIBLE WHILE DRILLING SUDDEN AND ERRATIC TORQUE AND DRAG LIKELY JUST BEFORE STRICKING CIRCULATION MAY BE RESTRICTED
DO NOT APPLY TORQUE, JAR DOWN W ITH MAXIMUM TRIP LOAD CIRCULATE HIGH DENSITY HIGH VISCOSITY SWEEPS SPOT ACID IF STUCK IN LIM ESTONE
-•-.o..~~ CIRCULATE HOLE CLEAN BEFORE DRILLING
,._:··~~
AHEAD MINIMIZE SEEPAGE LOSSES SLOW TRIP SPEED BEFORE BHA ENTERS SUSPECTED ZONE
Page 38
STUCK PIPE
HOLE PACK-OFF I BRIDGE
DRILU!R
'ni!NDS" DRILLING
~~-~
•
J~!.u.J.·
•,
TORQ UE
DRAG Sudden. Increasing, erratic
HOLE PROBLEMS
PRESSURE
OTHER
No change
Sudden. eHahc
No change
Overpull off shps
Hole fill
CONNECTION TRIPPING OUT TRIPPING IN
Increasing, erratic Overpull off shps Begms at depth of problem formaliOn Hole fill on bottom
lncreastng set down werght
r :-1
BACK REAMING
Overpull off slips
PUMPING OUT
Overpull o ff shps lncreastng, errattc
Increasing~
lncreasing, errattc
erratic
r
No change
Drag decreases when pumping
No change
Drag decrea~s when pumprng
RIG TEAM INDICATIONS SHAKER TRENDS LOGGER TRENDS MUD TRENDS
Blocky or angular cock fragments
Same as shaker trends Possible offset well data clues. Prognosed fractured
formation
-
No change.
PREVENTIVE ACTION
.
NOTE: With fractured lormatrons, mainlarnmg a good quality filter cake can help to support the formation in some cases . Generally, fractured format•ons requtre hme to stablltze Pnor to thts, the problem must
be controlled w rlh adequate mud propertres, sweeps and suffrcient crrculalion ltme to keep the hole clean Other recommendations: •
Circulate the hole clean before drilling ahead
•
Restrict tripping speed when BHA Is opposrte fractured rormat•ons and fault tones
•
Start I stop the drrll string slowly to avord pressure surges to the wellbore
•
Anticipate r eammg dunng trtps Ream fractured zone cautiously
•
Be prepared lor the potential of lost cuculauon when drrlllng fractured rormattons
•
Problem likely to slabrllze with lime
Page 39
STUCK PIPE
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
EXCESSIVE CASING RATHOLE
1-::~.~ CEMENT SQUEEZE JOB CEMENT KICK-OFF PLUG CEM ENT CAVING$ AT SHAKER AND/OR IN MUD LOGGER SAMPLES
~~::::: PROBLEM CAN OCCUR ANYTIME SUDDEN, ERRATIC TORQUE AND DRAG JUST =·- __ .,.. BEFORE STICKING
ATTEMPT TO BREAK t;HUNK:S WITH JARRING & TORQUE JAR IN THE OPPOSITE DIRECTION OF STRING MOVEMENT PRIOR TO STICKING APPLY JARRING FORCE & TORQUE GRADUALLY CIRCULATE HIGH DENSITY, HIGH VELOCITY SWEEPS
PREVEN TIVE ACTI ON: M INIMIZE CASING RATHOLE ALLOW SUFFICIENT CURING TIME ~,._
REAM CASING SHOE AND OPEN HOLE PLUGS -- ·• THOROUGHLY BEFORE DRILLING AHEAD
~~~~~CASING S~L~O~W:T~R~I~ P SPEED BEFORE BHA ENTERS SHOE OR PLUG DEPTH
::
Page 40
HOLE PACK-OFF I BRIDGE
STUCK PIPE
HOLE PROBLEMS
CIRCULATION IS ATTEMPTED W ITH THE BOTTOM OF THE DRILL STRING IN SOFT CEMENT PUMP PRESSURE CAUSES THE CEMENT TO FLASH SET HIGH PENETRATION RATE WHEN CLEANING OUT SOFT CEMENT
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
BLEED TRAPPED PUMP PRESSURE JAR W ITH MAXIMUM T R IP LOAD IN T HE
OPPOSITE DIRECTION OF STRING PRIOR TO STICKING
MOVE,~E~H
IF SET DOWN WEIGHT IS OBSERVED WHILE RIH, PULL 2 STANDS BEFORE CIRCULATION START CIRCULATING 2 STANDS ABOVE TOP OF CEMENT CONTROL DRILL WHEN CLEANING OUT CEMENT
Page 41
HOLE PROBLEMS
STUCK PIPE
HOLE PACK-OFF I BRIDGE
POOR HOUSE KEEPING ON THE FLOOR, HOLE COVER NOT INSTALLED
~=~;:;::J
JUNK FALLS INTO WELLBORE AND JAMS THE DRILL STRING
GENERALLY OCCURS WHEN BHA IS IN HARD FORMATION OR INSIDE THE CASING SUDDEN AND ERRATIC TORQUE AND DRAG ~~;.:; LIKELY JUST BEFORE STRICKING
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 TORQUE IF PROGRESS IS MADE IF MOVING DOWN. JAR UP WITH MAXIMUM TRIP LOAD, DO NOT APPLY TORQUE
GOOD HOUSE KEEPING ON FLOOR INSPECT HANDLING EQUIPMENT KEEP HOLE COVERED
Page 42
STUCK PIPE 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 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 o f platform wells to reduce the possibility of cement blocks
•
Reduce ttipping speed when BHA is entering the casing shoe or opposite open hole cement plugs
•
Start and s top the drill siting slowly to avoid pressure surges to th e wellbore
FT CEMENT
N •
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 washi ng dowf\ 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
•
Verify cement compressNe strength with cement company before drilling out
•
Control drill when cleaning out soft cement
the mud system wilfh chemiCal prior to d nllino out cement
JUNK
ACTION •
Inspect slip and tong dies regularly
•
Use good house keeping pract1ces on the rig floor
•
Install drill string wiper rubber as qu1ckty as possible
•
Keep hole covered when out of the hole
•
M a intain rig floor equipment in good operating condition
Page 4 3
STUCK PIPE
A stlck.i ng Ioree developed when differentia l pressure (overbalance) forces a stationary drill string into the thick filter cake of a permeable zone
FILTER CAKE
PERMEABLE FORMATION
~~~:T!!~~J;
Sandstone I fractured lime-stone
I
.·· develops A cake of mud solids on the hole . wall due to fluid loss
OVER BALANCE Wellbore pressure greater than formation pressure
STRING CONTACTS FILTER CAKE
STATIC FILTER CAKE
Angled wellbore 1 unstabilized BHA increases potential
STRING MOTION STOPPED No string motion or circulation develops static cake
LOW PRESSURE AREA
TIME DEPENDENT
Overbalance pressure across the contact area determines the d ifferential force
Page 44
DI FFER ENTIAL STIC KING
STUCK PIPE
HOLE PROBLEMS
CAUSE: DRILL STRING CONTACTS A PERMEABLE ZONE WHEN STRING MOVEMENT STOPS. A STATIC FILTER CAKE DEVELOPS HIGH OVERBALANCE APPLIES A DIFFERENTIAl STICKING FORCE TO THE DRILL STRING CONTACT AREA
WARNING: PROGNOSED LOW PRESSURE SANDS LONG IUNSTABILIZED BHA SECTIONS INCREASING OVER PULL, SLACK OFF WEI~HT I OR TORQUE TO START STRING MOVEMENT___j
l iND/CA TIONS:
I
OCCURS AFTER A PERIOD OF NO STRING MOVEMENT
c
4"
STRING CAN NOT BE ROTATED OR MOVED
• ~
, CIRCULATION UNRESTRICTED
I FIRST ACTION: 200Sq In Contact
l
APPLY TORQUE AND JAR DOWN WITH MAXIMUM TRIP LOAD
Alta
SPOT A PIPE RELEASING PILL IF TH STRING DOES NOT JAR FREE
DIFFERENTIAL FORCE
(;;~,~~ PREVENTIVE A CTION:
~
MAINTAIN MINIMUM REQUIRED MUD WEIGHT
1,200,000 LBS 4-
KEEP STRING MOVING WHEN BHA IS OPPOSITE SUSPECTED ZONES MINIMIZE SEEPAGE LOSS IN LOW PRESSURE ZONES MINIMIZE UNSTABILIZED BHA SECTIONS, USE SPIRAL DC's & HWDP CONTROL DRILl SUSPECTED ZONES
Page 45
STUCK PIPE
HOLE PROBLEMS
·DRILLER TRENDS
DRILLING CONN.ECTION TRIPPING OUT TRIPPING IN BACK REAMING PUMPING OUT
DIFFERENTIAL STICKING
I OF.•
TORQUE
DRAG
No change
Possible increase
PRESSURE
OTHER
No change
No change
Increasing overpull off slips Increasing overpull off slips Increasing overpull off slips Increasing overpull off slips
No change
No change
No change
Increasing overpull off slips
RIG TEAll INDICATIONS
SHAKER TRENDS LOGGER TRENDS MUD TRENDS
No change
High overbalance. Permeable formation depth, Permeability data to estimate stricking potentiaL
Increasing mud weight. Increasing plastic viscosity and low gravity solids. High API water loss. thick fiKer cake.
~--· ---------~ ~ ACnaN •
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 Ruid loss within specifications
•
Minimize BHA length when possible
•
Limit the length of unstabillzed BHA. Use spiral drill collars
•
KEEP THE STRING MOVING. Consider rotating the string during d rilling and tripping connections while BHA is opposite potential sticking zones
•
Preplan to minimize the down time for operations that require the string remaining static (surveys, minor repairs, et<;.).
•
In zones with high sticking potential, minimize seepage loss with plugging agents
•
Keep a pipe releasing pill ready at the well site when d ifferential stricking potential is high
Page 46
STUCK PIPE WELLBORE Hole diameter and/or angle relative to BHA geometry and/or sliffness will not allow passage of the drill string STIFF ASSEMBLY
KEY SEAT
M ICRO DOGLEGS
MOBI LE FORMATION
LEDGES UNDER GAUGE HOLE
;z~~~a~::::::~ BHA AT DIRECTION I ANGLE CHANGE DEPTH ;:;;.Zi;;.;:::;::;:;~ UNRESTRICTED CIRCULATION
IF MOVING DOWN WHEN STICKING ~~~"! OCCURRED, JAR UP W ITH MAXIMUM TRIP
LOAD, DO NOT APPLY TORQUE IF MOVING UP, TORQUE UP AND JAR DOWN W ITH MAXIMUM TRIP LOAD PREVENTIVE ACTION:
MINIMIZE BHA CHANGES, CONSIDER A REAMING TRIP LIM IT DOGLEG SEVERITY SLOW TRIP SPEED BEFORE BHA ENTERS SUSPECTED ZONE, PLAN TO REAM
Page 47
STUCK PIPE
HOLE PROBLEMS
WELLBORE GEOMETRY DIRECTION I ANGLE CHANGE
::0:~3i!~!'!~~~ ABRUPT CHANGE IN ANGLE OR
oi;:~~-~ DIRECTION IN MEDIUM SOFT TO MEDIUM HARD FORMATION
~-=~,.;~ HIGH STRING TENSION AND PIPE
-.
ROTATION WEARS A SLOT INTO THE FORMATION
WHILE POOH, THE DRILL COLLARS JAM INTO THE SLOT
HIGH ANGLE DOGLEG IN UPPER HOLE SECTION LONG DRILLING HOURS W IT H NO W IPER TRIPS THROUGH THE DOGLEG SECTION •. . ,.CYCLIC OVER PULL AT TOOL JOINT . INTERVALS ON TRIPS
~::':1m~
OCCURS ONLY WHILE POOH SUDDEN OVER PULL AS BHA REACHES DOGLEG DEPTH UNRESTRICTED CIRCULATION FREE STRING MOVEMENT BELOW KEY
~~~~~~ EA~T~DEPTH POSSIBLE IF NOT STUCK
: ::.:.;.:.·. , ..., .•..·.:- APPLY TORQUE AND JAR DOWN W ITH MAXIMUM TRIP LOAD ATIEMPT TO ROTATE WITH LOW OVER ;:,;.;~~~~~~ · PULLS TO WORK THROUGH DOGLEG
MINIMIZE DOGLEG SEVERITY TO 3°/100' OR LESS LIMIT OVERPULLS THROUGH ' SUSPECTED INTERVALS PLAN REAMER AND/OR W IPER TRIPS IF DOGL.EG IS PRESENT RUN STRING REAMER OR KEY SEAT W IPER IF SUSPECTED
Page 48
W ELLBORE GEOMETRY DIRECT ION I ANGL E CHAN GE
STUCK PIPE
HARD/SOFT INTERBEDDED FORMATIONS FREQUENT CORRECTIONS IN HOLE ANGLE OR DIRECTION BHA BECOMES JAMMED IN TH E SUCCESSIVE MICRO DOGLEGS
· . PROGNOSED HARD/SOFT INTERBEDDED FORMATIONS FREQUENT ANGLE/DIRECTION CHANGES DRILLING/SLIDING W ITH DOWN HOLE MOTOR ERRATIC TORQUE AND DRAG ON CONNECTION
IF MOVING UP WHEN STICKING OCCURRED, APPLY TORQUE AND JAR DOWN WITH MAXIMUM TRIP LOAD IF MOVING DOWN, JAR DOWN W ITH MAXIMUM TRIP LOAD, DO NOT APPLY
MINIMIZE DIRECTION I ANGLE CHANGES .· ·. •·.·.· .. :. BACKREAM FREQUENTLY WHEN DRILLING HARD/SOFT FORMATIONS SLOW TRIP SPEED BEFORE BHA ENTERS SUSPECTED ZONE
Page 49
HOLE PROBLE MS
STUCK PIPE
WELLBORE GEOM ET RY DIRECTION I ANGLE CHANGE
INTERBEDDED FORMATIONS. SOFT ROCKS • WASH OUT HARD ROCKS • IN GAUGE FRACTURED I FAULTED FORMATIONS STABILIZER BLADES AND TOOL UPSETS BECOME STUCK UNDER LEDGES
PROGNOSED HARD/SOFT INTERBEDDED FORMATIONS PROGNOSED FRACTURED/FAULTED FORMATIONS
MII~IMII<:t
DIRECTION I ANGLE CHANGES
MINIIMI<~E BHA CHANGES
Page 50
WELLBORE GEOMETRY HOLE DIAMETER DECREASE
STUCK PIPE
HOLE PROBLEMS
PRl:)GI~OS>ED
SALT OR PLASTIC SHALE
SUIJDEoN INCREASE IN OVER PULL OR SET WEIGHT :>UIJIJt:N TORQUE INCREASE W ITH FAST
un'""'"'
PLASTIC FORMATION
GENERAicLY OCCURS WHILE POOH POSSIBLE WHEN RIH AFTER A LONG PERIOD OUT OF THE HOLE POSSIBLE WHILE DRILLING IF FORMATION MOVES FAST STICKING OCCURS WITH BHA AT PLASTIC ZONE DEPTH CIRCULATION UNRESTRICTED OR SLIGHT RESTRICTION POSSIBLE
MOVING DOWN, JAR UP WITH MAXIMUM LOAD. DO NOT APPLY TORQUE FRESH WATER IF IN SALT. (CONSI CONTROL)
COI~SI[lER
ECCENTRIC PDC BITS
TRIP SPEED BEFORE BHA ENTERS SU::>PECTEcD ZONE
Page 51
STUCK PIPE
WELLBORE GEOMETRY
u"'""·'"'..., HARD ABRASIVE ROCK WEARS GAUGE PROTECTION
i C<)REDHOLE SECTION UNDER GAUGE
GAUGE PULLED BIT AND STABILIZERS · NEVER FORCE BIT THROUGH TIGHT SPOTS REAM THE LAST 3 JOINTS TO BOTTOM . BEGIN REAMING 3 JOINTS ABOVE CORE HOLE SECTION SLOW TRIP SPEED BEFORE BHA ENTERS SUSPECTED ZONE
Page 52
STUCK PIPE Problems are observed only when BHA Is moving in the hole
ECTION
Surge to start circulation
Increasing, erratic
Momentary over pull & set down
Increasing, erratic overpull with BHA al
TRIPPING OUT TRIPPING IN BACK REAMING PUMPING OUT
Momentary over pull & set down
zone lncreastng, erratic set down weight Erratic
Increasing. erratic
Increasing, erratic overpull
:::·-= ..-
·.:,. ".. '
'
. ':-;:_
No change
Momentary over pull
No change
Momentary over pull
~f&i:-:;;.=. ;._... ~ ~-. ~ ~ ~....._ ~~.~ .. .-J:.:.~·~-!$~~---..;jJ~.........~. . -~--=--"'•:'o.'
SHAKER TRENDS LOGGER TRENDS MUD TRENDS
·.
-
L
0
_: . , -~- _
.__i-~~-~ :
No change No change No change
•
Optimize BHA design (run only what is required) and when possible . minimize BHA stiffness
•
f'tan a reaming trip ff the new BHA is locked up andlor a note geometry problem IS suspecte
•
Slow down trip speed before BHA enters kick off or dogleg depth, depth of micro dogleg and/or ledges, mobile formation depth
•
Minimize dogleg severity to 3°/100' or less. M inimize rotating hours below a sharp dogleg without a wiper or reaming trip
•
Consider using key seal 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
•
M inimize sharp. frequent wellbore course changes
•
Avoid prolonged circulation In suspected micro dogleg section to prevent hole wash out and forming ledges.
•
With mobile salts consider using a slightly under saturated mud system to allow a controlled washout. If necessary. increase the mud weight to help slow down salt intrusion.
•
Consider drilling mobile salts with eccentric PDC bits. Plan regular wiper trips to keep the hole
section open •
Use hard faced stabilizers and select bits with extra gauge protection if abrasive formations are d rilled
•
Gauge the old b1t 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 joint back to bottom on every trip
Page 53
STUCK PIPE
INfTIAL ACnON:
1. If sticking O
2. Stop Of rOduce cirei.Mtion when cocking lhe jar and when jarring down.
NOTE: Pomp Pt<>..
3. Continuo Jarring until the string Is tree or an altemative decision is made. Jarri"Q f-Qf 10+ hours may be necessary. SECONOARY ACnON: Spot acid if stuck in l imestone or chalk . Spot trash water with mobile SO.It.
WHEN THE STRING COMES FREE: \ , Increase circulation to maximum rate, rotate and work the
string. 2. Ream I backleam the hole Secl)()ll lhor·o ughly.
ACnoN TO ESTABUSH CIRC: 1. Apply tow pomp ptessure (200 • 400 pst). Maintain pressure if
ACnON TO ESTABLISH CIRC: 1. Appty iQw pump pressure (200· 400 ps1), Maintain pressure il
restricted circulation is possibl&.
restrided circutation i s possible.
2. 00 NOT JAR UP!!! APPLY TORDUEIII Slacl< off 10 MAXIMUM set down weight. Alk>w sufficient lime f01 a hydrau1ic jar to ttlp (4 • 6 min for long cycle. see jar manual) ..
2. DO NOT JAR DOWN!!I APPL Y
3. II the string OOC-s not come free. DO NOT JAR UPII Jar DOWN until the string comM tree Of an attemative decision is made.
3, If tne ~ring
2 . Wori< M AXIM UM limit torque down to
the st\Jck Cfepth and hold the torque in the
TOROOEIII Apply MAXIMUM ovarpuU to &at. AlbN sufficient time fOf a hydraulic jar to trip (4 • 8 min l or long cvcte. see jar manual).
5. Allow sufficient time tor a hydraulic jar t-o tfip (4 • 6 min tor king cydO. see jar manual).
Jarring down tor 10+ hours may be
alternative docision is made. Jarring up ftx 10+ hours may bG
necessary.
reQuired. WHEN CIRC. IS ESTABLISHED: 1. Slowly increase pump speed to
maximum rate. When pos.sible, wortc the Siring and circulate the hote elean from bl1 depth.
lho Wing 8flef circulate the hole dean from bil d&pth.
6. II the stMg doeS not come free. hotd torquo in tl\0 string and continue jarring down with maximum lrip toad. SECONDARY ACnON: If the string dOGs not como lroo aftor S to 10 jar blows, conlinue
ma>c rate. When pos.sible. work
willie
2. Ream I~ sectJon until the hole is dean.
Ream the section until the hole
3. If POOH to log and I or run casing, return to bottom and circulate the
• Continue RIH until oxoessive sel
4sclean.
hole clean.
QUESTION
minimum. 4. SlaCk OM 10 MAXIMUM seH:town lim it!
until the string Is free or an
WHEN CIRC. IS ESTABLISNEO: 1. Sbldy inattase pump speed 10
3 . Stop or reduce pump spe&d 10
down woight is obsotVOd, circulate the h ole dean.
ANSWER
2. Circolaua at maximum ra1e to crean ... hole. 3. Chock the proper mud spoclticatklns.
RESULTS
Moving up
The three numbers 2 . 0 , 2 a re circled in the Moving Up row.
Pipe motion a!!er slicl
Dn Impossible
The three numbers 0. 0. 0 are circled in the Down Impossible row.
Pipe ro tatioo a fter sticking?
Rot. Impossible
The three numbers 0. 0 , 0 are circled in the ROI. Impossible row.
Circ. press. after sticking?
Circ. Impossible
Pipe motion prior to stiO'ktng?
Add tlle numbers in 1he co4oums.
The three numbers 2 . 0. 0 are cirded in the Circ.lmpossible row.
TOTALS=
4, 0, 2
The probable sticking mechanism Is the column with the highest total number (4) , Pack-oil/ Bridge
Page 54
LOST CIRCULATION
Measurable loss of whole mud (liquid phase and solid phase) to
LOST CIRCULATION the formatlon. Lost circulation can occur at any depth during any operation
ADVERSE EFFECTS ON DRILLING OPERATIONS : U"'l 0: PRODUCTION HOLE INT LSURFACE HOLE Loss of drive /conductor shoe
Loss of Huld level monitoring
loss of Huid level monitoring
loss of formation evaluation loss or formation evaluation
Hole cleaning problems Hole cleaning problems
Hole cleaning problems
Hole bridge /collapse Hole bridge /collapse
Hole bridge /collapse
Stuck pipe Extended well bore exposure time
Extended wellbore exposure
Well control event StucK pipe
time
Well control event
Stuck pipe
Under ground blowout
Well control event
Additional casing string
Underground blowout
Loss otwell
Additional casing string Production zone damage
LOST CIRCULATION MECHANISMS PRESSURE INDUCED FRACTURE
Well bore pressure exceeds fracture pressure of the formation caus,ing the rock to crack ope-n (fracture)
NATURALLY EXISTING Over balanced wellbore pressure is exposed to a formation FRACTURES I HIGH with unsealed fractures or high permeability PERMEABILITY CAUSES OF LOST CIRCULATION PRESSURE INDUCED FRACTURES NATURAL FRACTURES I PERMEABILITY Excessive mud weight
Unconsolidated formation
Annulus friction pressure
Fissures I fractures
Wellbore pressure surges
Unsealed fault boundary
Imposed I trapped pressure
Vugular I cavernous formation
Shut-in pressure Low formation pressure
Page 55
HOLE PROBLEMS
LOST CIRCULATION
MECHANISMS
PROGNOSEO LOSS ZONE EXCESSIVE MUD WEIGHT LOW FRACTURE STRENGTH
MAY BEGIN WITH SEEPAGE LOSS, POSSIBLE TOTAL LOSS PIT VOLUME LOSS
Page 56
LOST CIRCULATION
WELLBORE PRESSURE IS OVER BAlANCED TO FORMATION PRESSURE MUD IS LOST TO NATURAL FRACTURES AND/OR HIGH PERMEABILITY
PROGNOSEDLOSSZONE LOST CIRCUlATION CAN OCCUR AT ANY TIME DURING ANY OPEN HOLE OPERATION
MAY BEGIN WITH SEEPAGE LOSS, TOTAL LOSS POSSIBLE STATIC LOSSES DURING CONNECTIONS I SURVEY
REDUCE PUMP SPEED TO 1/2 PULL DRILL STRING OFF BOTTOM, STOP CIRCUlATION ZERO STROKE COUNTER, FILL ANNULUS WITH WATER OR LIGHT MUD RECORD STROKES IF I WHEN THE ANNULUS FILLS UP
MINIMIZE MUD WEIGHT CONTROL PENETRATION RATE MINIMIZE WELLBORE PRESSURE SURGES
Page 57
LOST CIRCULATION
HOLE PROBLEMS
SEEPAGE LOSS (< 20 BBLSIHR)
MECHANISMS
LOSS SEVERITY CLASSFICATIONS PARTIAL LOSS TOTAL LOU (> 20 BBLSIHR) (NO UTUIIIUIS) IMMEDIATE DROP IN FLUID LEVEL WHEN PUMPING IS STOPPED
GRADUAL LOSSES OPERATION NOT INTERRUPTED
SLOW TO REGAIN RETURNS AFTER STARTING CIRCULATION
POSSIBLE WARNING OF INCREASED LOSS SEVERITY
OPERATIONS USUALLY INTERRUPTED
l
RETURN FLOW STOPS IMMEDIATELY PUMP PRESSURE DECREASE STRING WEIGHT INCREASE OPERATION SUSPENDED
REMEDIAL ACTION REQUIRED
REMEDIAL ACTION REQUIRED
-
METHODS FOR LOCATING I rut.'ll DEPTH Successful treatment of lost circulation depends greatly on locating the depth of the loss zone
SURVEY METHODS
PRACTICAL
IIE1'HbD8
•
TEMPERATURE SURVEY
0
•
ACOUSTIC LOG
•
• GEOLOGIST I LOGGER IDENTIFIES POTENTIAL LOSS ZONE
RADIOACTIVE TRACER
•
SPINNER SURVEY
• •
PRESSURE TRANSDUCER
OFFSET WELL DATA
• MONITORING FLUID LEVEL TRENDS WHILE DRILLING
HOT WIRE SURVEY
FOR 0
SURVEY TOOLS NOT ALWAYS AVAILABLE
•
CONSIDERABLE TIME REQUIRED TO RUN SURVEY
•
SURVEYS REQUIRE LARGE VOLUME OF MUD
0
RESULTS OFTEN DIFFICULT TO INTERPRET
0
POSSIBILITY OF LOSING SURVEY TOOL IN THE HOLE
Page 58
il
LOST CIRCULATION SOLUTION GUIDELINES
ACT10N MINIMIZE MUDWT
FORMATION "HEALING TIME"
GUIDEUNES FOR LOST CIRCULATION SOLUTIONS CONSIDERATIONS RESULTS 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
More successful with fresh water mud losl to shale formations
Soft shales deform with formation stress helping to "hear' the fracture
Better results will1 LCM
Normal S . 8 hours walt time with string
in casing
LOSSCIRC MATERIAL (LCM)
Effectively bridges. mats and seals small to medium fractures I permeability
Less effective with large fractures, faults
Ineffective with cavernous zones Increase LCM lbslbbl with loss severity
SPECIALTY TECHNIQUES
A plug base is pumped into the loss zone followed by a chemical activator The two materials form a soft plug
Can be used in production zones
Increased risk of p lugging equipment Plug breaks down with time
CEMENT
Cement slurry is squeezed into the toss zone under injection pressure The slurry cures
DRILLING BLIND
Provides a "fit-to-form" solid plug at o r near the stress of the surrounding
formation
to a solid plug
In some cases, the only practical solution is to drill without returns
Not a consideration where well control potential exist Set casing in the forst compentent formation
FOR SUCCESSFUL LCM RESULTS • Locating the loss zone and accurate pill placement is vital. Position the string +/-100 feel above loss zone, do not stop pumping until the pill clears the bit •
Insure the base mud viscosity will suspend the LCM volume added. Add fresh gel to a premixed LCM pill immediately before pumping, fresh gel continues to yield after spotting
• An effective LCM pill bridges, matts and then seals the loss zone. particle size distribution and pill formulation must satisfy these requirements Consult the LCM product guide prior to applying the pill
•
Use large nozzle sizes if the loss potential is high. Keep the string moving during pill spotting operation to avoid stuck pipe
Page 59
LOST CIRCULATION
HOLE PROBLEMS
..
RESTORING CIRCULATION
LOSS CIRCULATION MATERIAL (LCM) ,
"
FINE (F)
A portion of the material will pass through the shaker
screens GRADES
MEDIUM (M) Majority of material will screen-out at shakers. COARSE (C) All material will screen-out at shaker Will plug jets and down hole tools. Recommended with open-ended pipe
FIBROUS & FLAKED
Non-rigid materials that form a mat on the hole wall to provide a foundation for normal filter cake development
GRANULAR
-
Rigid malenals that bndge and plug the permeability of the loss zone
-
·~
LCMBLEND
A combination of fibrous. flaked and granular materials in one sack
CELLULOSTIC
Sized wood derived materials used to prevent seepage /partial loss
CALCIUM CARBONATE
Sized limestone or marble (acid soluble) used for seepage /partial loss in productior zone
- SIZED SALT
Granulated salt (water soluble) developed for seepage /partial loss in production zone in salt-saturated systems
SEEPAGE LOSS SOLUTIONS (< 20 BBLSIHR) FIRSTACnoN
•
• • •
• •
RECOVERY Add LCM pill In 5 • 10 PPB increments, Evaluate results 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
Reduce ROP to limit cuttings load M inimize mud rheology
-
NON-PRODUCTIVE INTERVALS
M tnimtze GPM
WBM:
Minimize wellbore pressure surges
Minimize mud wt Consider pulling into casing and waiting 6 to a hours
OBM I SBM:
LCM Blend (F) 5 · 15PPB LCM Blend (M) 5 · 15PPB FlaKed (FIM) 10 • 20 PPB
Cellulosic (F/M) 2 -25 PPB
PRODUCTION ZONE EXPOSED WBM:
OBMISBM:
L1mestone (FIM) 5 · 30 PPB
Cellulosic (FI M) 2 • 25 PPB Limestone (F/M) 5 • 15 PPB
THE LCM M IXTURES SHOVVN HERE ARE INTENDED AS A GUIDE WHERE NO FIELD EXPERIENCE EXIST, SOME SITUATION S MAY REQUIRE 2 • 6 PP8 LCM CONCENTRATIO N IN THE TOTAL MUD SYSTEM. CONSULT YOUR MUD COM PANY FOR AVAILABLE PRODUCTS AND PILL FORMULATIONS BEST SUITED FOR THE AREA.
Page 60
LOST CIRCULATION PARTIAL LOSS SOLUnONS (> 20 BBLSIHR) FIRSTACnON
•
Reduce ROP to limit cuttings load
•
Minimrze mud rheology
• •
Reduce GPM
• •
RECOVERY Add LCM pill in 5 -1 0 PPB incremen1s. Evaluate results over 2 circulatio ns before increasing to next level of LCM concentration. Mix in 30 to 50 bbl batches dic1ated by hole size. Consider spotting LCM pill before POOH
NON-PRODUCTIVE INTERVALS WBM:
Minimize well bore pressure surges
OBM /SBM:
LCM Blend (M) 15 - 25 PPB LCM Blend (C) 15 - 25 PPB walnut (M/C) 10-20 PPB
10-25 PPB 10 -25 PPB 5 -15 PPB
PRODUCTION ZONE EXPOSED
Minimize m ud wt Consider pulling into casing and waiting 6 to 8 hours
Cellulosic (F/M) Cellulosic (C) walnut (M)
W BM:
OBM /SBM :
LCM Blend (F) 5 - 15 PPB LCM Blend (M) 5- 15 PPB Cellulosic (M) 5 - 15 PPB
Cellulosic (F/M) Limestone (F)
2-25PPB 5 - 15 PPB
GUIDELINES TOTAL LOSS SOLUTIONS RECOVERY
FIRST ACTION • Pull off bottom, keep
Formulations for the specialty pill and cement are dictated by conditions of each event
string moving
NON-PRODUCTIVE INTERVALS • Ffll annulus .with water
or light mud
• Record strokes ij I
OBM /SBM:
WBM:
30 - 40 PPB LCM Pill Specialty Pill Cement Squeeze
40 PPB LCM Pill Specialty Pill Cement Squeeze
when annulus fills up
PRODUCTION ZONE EXPOSED • Consider pulling into
the casing
• Minimize wellbore pressure surges
OBM /SBM:
WBM: 40 PPB LCM Pill Specialty Pill Cement Squeeze
30 - 40 PPB LCM Pill Specialty Pill Cement Squeeze
ADDRESS RESERVOIR NEEDS
ADDRESS RESERVOIR NEEDS
THE LCM MIXTURES SH6WN' HERE ARE IN11'ENDED AS A GUIDE WHERE NO FIELD EXPERIENCE EXIST. SOME SITUATIONS MAY REQUIRE 2 - 6 PPB I!.CM CONCENTRATION IN THE TOTAL MUD SYSTEM. CONSUl.T YOUR MUD COMPAN'I' FOR AVAILABLE PRODUCTS AND PILL FORMULATIONS BEST SUITED FOR T HE AREA.
Page 6 1
Page 62
LOST CIRCULATION SPOmNO PROCEDURES FOR LOST CIRCULAnON MATERIAL (LCM) •
Locate the loss zone
•
M ix 50 - 100 barrels of mud with 25 - 30 ppb bentonite and 30 - 40 ppb LCM
•
Position the d rill string +/-100 feet above the loss zone
•
If open-ended, pump 1/2 of the pill into the loss zone. Stop the pump, waij 15 minutes and pump the remainder of the pill
•
Jr pumping through the bit, pump the entire pill and follow with 25 barrels of mud
•
If returns are not regained. repeat procedure If retu rns are not regained, wait 2 hours a nd repeat procedure
•
If returns are not regained after pumping 3 pills, consider other options to regain circulation
SPOmNO PROCEDURES FOR SPECIALTY PILL •
If possible, d rill through the loss interval . Pull out of the hole and return open-ended
•
Position the string +/-100 feet above the loss zone
•
Clean t.h e mixing pit thoroughly. Mix 50 barrels of desired specialty pill
•
Pump down the d rill string and place in the suspected zone. If annulus is not full. pump m ud down the annulus white pumping pill down drill string
•
When annulus fills and squeeze is in place, apply 150 - 200 psi on annulus. This wilt "sofl squeeze" the material into the loss zone
•
Jr possible, drill1hrough the loss interval. Pull out of the hole and return open-ended
•
Position the string +/-100 feet above the loss zone
•
M ix 100 sx of cement and 100 sx of bentonite with 50 barrels of diesel (slurry 1111- 11.5 ppg, yield1.39 cubic feet per sack )
•
Pump down the drill string, 15 barrels of water-free diesel ahead and behind the gunk slurry
•
When the lead diesel spacer reaches the bit, close the BOP and pump mud down the annulus
•
Pump 4 bblslmin down the string and 2 bblslmin down the annulus until the tail diesel spacer clears the string
•
Reciprocate the string slowly, do not reverse circ ulate
•
Pull the d rill string clear of the squeeze. Mix and place the squeeze with a cementing unit, possible
•
Wait 8+ hours for the gunk to cure, repeat procedure if returns are not regained
•
It may be necessary to d rill out the gunk before repeating the procedure
SPOmNO PROCEDURES FOR GUNK PILL
Page 63
n
LOST CIRCULATION
HOLE PROBLEMS
PREVENTION
SPO I liNG PROCEDURE FOR CEIENT The cement slurty 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 11)0 feet above the loss zone
•
Mix and pump 50 to 100 bbls of cement slurty
• • •
Follow the slurry with a
Wah 6 to 8 hours and attempt to fill the a nnulus
•
It may be necessary to drill out the cement before repealing the procedure
suffoc~e nt
volume of mud 01 water to balance the U·Tube
Repeat the procedure d returns are not rega1ned
LOST CIRCULATION PREVENTION GUIDEUNE8 Prevention of lost circulation must be considered i n the wen plann~ng, dnlling and post analysis phases •
Design the easing program to ease-off low pressure or suspected lot circulation zones
•
Ma1ntain mud weight to t.h e min1mum required to control known fOimation pressures.. High mud weJQhiJs one of the major causes of lost circulation
•
Pre-treat the mud system with LCM when dnU1ng through known lost corculauon Intervals
•
Maintain low mud rheology values that are st1tl suffoc-t to clean the hole
•
RotittJng the drill slfiny when :.lartiog drw&ation hetp5 to break the gel$ end mtmmiz:o pymp pressure
surges •
Start circulation slowly after connectiOns and periods of non-circulation
•
Use minimum GPM flow rate to clean the hole when drilling k nown lost circulation zone
•
Control drill known lost circulation zone to avoid loading the annulus with cuttings
•
Reduce pipe tripping speeds to minimize swablsurge pressure
•
Plan to break circulation at 2 to 3 depths white tripping in the hole
•
Minimize annular re,strictions
•
Consider using jet sizes 01 TFA that Will allow the use of LCM pills ( 12132"' tets +)
•
Be prepared for plugging pump suctiOns. pump d1scharge seteen. dnll string screens. etc
•
Be prepared for mud losses due to shaker screen plugging
Page 64
LOST CIRCULATION
HOLE PROBLEMS DRILLING BLIND
PRECAUTIONS WHILE DRIWNG WITHOUT RETURNS Circumstances may dictate drilling blind until 50 feet of the next competent formation is drilled. Casing is set to solve the lost circulation problem. A blind drilling operation must have Drilling
Manager approval
•
Insure an adequate water supply is available
•
Use one pump to drill and the other pump to continuously add water to the annulus
•
Assign a person to monitor the now line at all t1mes
•
Closely monitor torque and drag to determine when to pump viscous sweeps
•
Closely monitor pump pressure while drilling for indications of pack-off
•
Conlrol drill (if possible) at one joint per hour
•
Pick up off bottom every 15 feet (3m) drilled to ensure the hole is not packing off
•
Keep the pipe mov10g at all times
•
Maintain a 400 • 500 bbl reserve of v1scous mud ready to pump
•
Consider spotting viscous mud on bottom prior to tripping or logg1ng
•
Stop dnlhng and consider pulling to lhe shoe if pump repairs are required
•
Stan and stop pipe slowly and minimize pipe speed
•
Consider spotting a viscous pill above the BHA prior to each connection
•
Prior to each connection, circulate and w1pe the hole thoroughly
•
Do not run surveys when drilling blind
•
If circulation returns. stop drilling. Raise the drill string to the shut-in position. Stop the pumps and check the well for flow
•
If flow is observed, close the BOP a nd observe shut~ in pressures:
• • •
No pressure • Slowly circulate bottoms up through 2 open chokes Pressure Observed • Slowly circulate the kick with the Circulation Method and present mud weight. Be prepared for a n underground blowout condition
At all times to pump cement to the well
Page 65
RIG REPAIR
An interruption in planned operations caused by a breakdown In the drilling rig equipment. Running rig equipment to failure is not cost effective for the Contractor. Operator. or wellbore
UNSCHEDULED RIG REPAIR
IMPACT OF UNSCHEDULED RIG REPAIR OPERATOR DRILLING CONTRACTOR WELLBORE FINANCIAL PENALTIES
HIGH RISK OF OTHER UNSCHEDULED EVENTS
COST OF EMERGENCY REPAIR POSSIBLE PERSONNEL INJURY EXTENSIVE EQUIPMENT DAMAGE
INCREASED WELL COST DELAYED PRODUCTION
EXTENDED EXPOSURE TIME
LOSS OF PRODUCTION
LOSS OF HOLE SECTION LOSS OF WELL
LOSS OF FUTURE CONTRACTS
PRIMARY CONTRACTOR AND OPERATOR OBJECnYES CONTRACTOR OPERATOR NO PERSONNEL INJURY
NO PERSONNEL INJURY
NO WELL CONT ROL 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
PREVENnYE MAINTENANCE PROGRAM (PMP)
A program designed to schedule regular Inspection, maintenance 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 PREVENnYE MAINTENANCE PROGRAM CLOSED LOOP • Management to rig
CREW FEED BACK RECORD KEEPING • Refining and tailoring the system
AUDITING
• Equipment history
• Through Inspections
• Rig to management
• Equipment trends
• Well designed checklists
• Roles defined
• Equipment maintenance • Follow-up plans/ reports
• Clear guidelines
Page 66
RIG REPAIR -~~~--~~-~-------------
~------
--
COMPREHENSIVE PMP EQUIPMENT LIST • MAIN ENGINES
0
HIGH PRESSURE MANIFOLDS I VALVES I HOSES
• GENERATORS I SCR SYSTEMS
•
HYDRAULIC OPERATING SYSTEMS
• MOORING I STATION KEEPING SYSTEM
• COMPRESSED AIR SYSTEM
0
BALLAST AND BILGE SYSTEM
°
0
TENSIONING EQUIPMENT
0
CRANES PIPE HANDLING SYSTEM
• BOPE I CONTROL SYSTEM
° CIRCULATING SYSTEM
• RISER I DIVERTER SYSTEM
0
0
• BULK MIXING SYSTEM
HOISTING EQUIPMENT
• TOP DRIVE SYSTEM
_:_~_o_r_A_R_Y_s_y_s_T_E_M_ _ _ _ _ _ _ _
MUD PUMPS
• SOLIDS CONTROL SYSTEM
I•
RIG COMPUTER SYSTEMs_ _ _ _ _ _ _...J
PMP FREQUENCY SCHEDULE 0
• HOURLY 0 DAILY WEEKLY
0
0
BI-MONTHLY
• QUARTERLY 0 EVERY FOUR MONTHS
• BI-WEEKLY 0 MONTHLY
• SEMI-ANNUALLY • ANNUAllY
EVERY TWO YEARS
• EVERY THREE YEARS • EVERY FOUR YEARS 0 EVERY FIVE YEARS • EVERY EIGHT YEARS
BENEFITS OF A SUCCESSFUL PREVENTIVE MAINTENANCE PROGRAM
•
Ensure equipment life .expectancy
•
Reduce down time for unscheduled rig repair
•
Lower well cosl
• •
Reduce severity o l damage to equipment
•
less chance of personnel injury
• • •
Increase contractor profit margm
Component failure frequency records defines rig and shore base spare parts inventory
•
Increase operator awareness of the contractor's operational needs
•
Opportunity for contractor 1nput/ involvement during well planning
Maintenance is less costly than emergency repair
Reduce risk of s tuck pipe, well control problems. other unscheduled events
EVALUATE RIG REPAIR FAILURE SEVERITY • WHO SHOULD BE NOTIFIED
0
ARE PERSONNEL OR THE RIG IN DANGER
• WHAT IMMEDIATE ACTION IS REQUIRED
0
IS THE WELLBORE IN DANGER
• CAN NORMAL OPERATIONS CONTINUE
0
WHAT SAFETY PRECAUTIONS ARE REQUIRED
• CAN PARTIAL OPERATIONS CONTINUE
° CAN THE FAILURE BE REPAIRED O N SITE
0
IS OPERATIONAL SHUT DOWN REQUIRED
0
Page 6 7
PREVENTATIVE ACTION PLAN
INTEGRATED PREVENTATIVE MAINTENANCE PROGRAM (IPMP)
,.. Sorvloe forwa1d Ule ,.. 80atS:
•· lftlg~Rcl, . -~- seM:eFt>c<•· SeMceBOPAcCU• · Chcng&s-~, . eo-
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LEGEND
1 2.
LOW RJSK MAINTENANCE
3. HJGH RISK MAINTENANCE •
4,
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14. RepjooO WIG 1loel
15. Setvlce ()pe(ala 9·22·2pu
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C£¥EW UN!J 5eiii!CO liOnS. #1 6- 5eiii!CO 1'\lmp # 1 SofVlce Engine 7. SeMce P.lonl< 11 a lotiNoa SOMe& !tons. lf.2 9 SQMeo 1'\lmp #2 SeMce Engine 10
OT~R
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Days From Spud
15
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45
50
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60
65
I
70
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-
Depth
30"
1284'
20"
21100'
13-318"
5080'
9-518"
12.250'
r
14,540'
17·112'" HOLE 13-3/S" CSG Run Csg
woe ,_,
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RIG ___,. 1•2 ,..-10-12·29 IPMP
Well
n.
SEOMCE COM"""' .....N'I'ENANCt: LIST
PlANNED IAAJNTENANC£ •
SERV~ IPMP
,. • Seo. CoruL 1\.mpt; ... 4,6,6
22 • Seo. ~ Ma111old
• • 5e1v1C:e Man Enginelll · Se1V1ce CoruL 1\.mpt; "· Sol'llca Slalboad Service Gene«Jtcn • • 4.5.6 ••· crone >· SoMce./<1~- -~- -- Soritoecentl\mpt; , • Slfi:I'CUI M tN> 11 • SoMcolop 0rt.e ~ . 1, SeMce Ft>c< IV $ . SerW:;:e PQrr Oone ,, • SGtVtee ~ 9f$1Qt'n,,. it:::llm 1·
...... ... ... .....
-
RIG EQUIPMENT MAINTENANCE I.IST:
RunC~og
woe
-
..... l~ ........~ •~......~.1./2'"..~ ii ~ 7" ..
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RIG REPAIR ..
.
DRILUNG SYSTEM BREAK DOWN EMERGENCY PROCEDURES If rig equipment failure shuts down a major drilling system, immediate action must be taken to protect the personnel, rig and wellbore from associated events
DRILUNG SYSTEM BREAKDOWN STATION KEEPING
INITIAL RESULT
SECONDARY RESULT
• Rig drifts or drives oft location
• Stuck pipe
• Stop rota boo and cuwtauon
• SOP I ns.er damage
• Pos.tlon tooljoint above the hang·off ram
• Dnll stnng ts sheared-off • Onll stnng damage 1 • Upper manne ns.e.r
connector unlatches
ACTION PLAN
• Surface equ•pment failufe I damage
• Ck>se hong-off tam$ ~ncf $lack· off lo Pf8determl00d ......e.gru • lmtiate dnll1ng conuactO(s e-mergency procedures
f-
TOTA~ RIG POWER
• Loss of MattOn keep!~
• R.g drlft·off dama~
• S1an emergency generator
• Loss ol ho~.ng.
• Studt pipe
• lnitlat& preliminary disconnect procedure
rotation, ciccutatioo • Well eot~l rol • Surface equipment
• Rai~o d(tll wing off bOttom w1lh mot•on
compensator
failure I demage • Ctrculate Wtlh cetnenting pump • Monitor well for TOTAL DRilLING POWER
Po~~!ble
ng drift • c>fl
now
• Possible loss of station keep!OQ
•
• lou of hoisting, rotahoo, Cfi'Cutatton
• Stuck pipe
• Initiate pre-Jimlnary disconnect procedure
• Well control
• Circulate with cemenhng pump
• Start emergency generj tor
damage
• If possible. rotJte drill string Wllh power tongs • Monitor wen fOf TOP DRIVE SYSTEM (TOSl
• Stucj( pipe
• Pos.sii>Se lou ot ro«ahon, hO!stlnQ, circulalion
Row
• If pos.sible, trip to casing shoe tor
re-oalr
• Well control
• If not possib&e. set slips, tie stip hand.'es and rotata- pipe in slips
• If possible. og ~up to clrcu:late • Monitor well for HOISTING S YSTEM
• Can~c rai&e the drill StrM19
• Stuck pipe
flow
• Contmue circulation I rotatton • Reciprocate dril suing with
motion compennt01 ROTATING SYSTEM
• St~k. pipe
• Canno-1 rotate the dtil Slt it'\lg
• Reciprocate d11ll string • Trip to casing 1hoe for repair
• If possible, rotate drill string with power tongs • Maintain fllll circulation CIRCULATING SYSTEM
WELL CONTROL SYSTEM
• C3nnot Ctrcul,le the wellbore
• Cannot shut·in during k•Ck
• Slutk pipe
• Trip to easing &hoe for repair
• Wei oontrol
• Rotate 1 r~lprocate lhe dnll string if repair Is made while in open hole
• Personnel l"jury
• Non emergency .. &eet.Jre the well to make repairs
• Equlpmem csam8ge • Biowout • loss of well • Environment.al damage
Page 69
• Eme
DOWN HOLE EQUIPMENT FAILURE An interruption in planned operations caused by drilling /evaluation tool failures other than drill string failures. Down hole tool selection and operation is critical in the reduction of tool failure
•
Drilling engineer specifies equipment
•
Drilling foreman orders equipment
•
Toolpusher inspects/checks equipment
• Driller picks up/runs equipment equipment • Rig team post analyzes L---------------------_________________________
DOWN HOLE MOTOR SHOCK sue
_J
Motor stops drilling
------~~--~-----------------------1 Seal washout
DRIUINGJAR MWD /LWD
Dump valve, software, LCM plugging
LOGGING SURVEY EQUIPMENT SPECIALTY EQUIPMENT not release, incompatible with other
PACKER I LJS I I 00LS
METAL FAnGUE
Cyclic stress reversals
IMPROPER TOOL SELECTION
Loads exceed design
IMPROPER TOOL OPERATION
Untrained personnel, inattention
EXCEEDED DESIGN LIMITS
Accidental llntentional over1oad
EXCEEDED DESIGN LIFE
Economic based, untrained personnel
TRANSPORTATION I
Untrained personnel
lim~s .
incompatible with other tools
HANDLING DAMAGE HOSTILE ENVIRONMENT
H S, CO , high temperature, corrosive mud, high hard abrasive formations
DESIGN I MANUFACTURING
Quality control failed
Page 70
DOWN HOLE EQUIPMENT FAILURE Selecting the right tool for the job can significantly reduce too failure. Following a standardized tool selection procedure ensures the right tool is selected
• WELLBORE CONDITIONS DOWN HOLE ENVIRONMENT
TOOL PHYSICAL PROPERTIES
COMPATIBILITY
OPERATIONS
Temperature limitations of tools H,S, CO,. Corrosion resistance Oil resistant rubber goods Hydrostatic pressure limitations Hole angle limitations Hole size versus tool size • DIMENSIONS Length, OD. ID or 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 wort< with other equipment • OPERATING PARAMETERS
Minimum J maximum flow rate Minimum I max·imum operating pressure Torque I tension limitations Recommended operating hours Is a tool operator needed I provided Special handling tools required Are special operating instructions required/provided Operating manual provided Safety Recommendations Settings I calibration data
Maintenance requirements • FISHING TOOL METHODS FISHING Tool dimensions diagram provided Required fishing tools I ease ol fishing Fishing records available Tool lost-in-hole consequences
SUPPORT
QUALITY CONTROL
COST
LIMITATIONS
Back up tools readily available I delivery time Are spare parts needed I readily available Transportation problems I hazardous cargo Air transportable Required deck space I deck toad • RELIABILITY OF TOOL New o r rebuilt tool Hours since last rebuilt/ inspection records Performance record of loot on offset wells Performance record ol tool worldwide Operating/standby rental rates I repair agreements Lost-in-hole charges I insurance Success/failed performance rate
Depth I external pressure limitation Yield strength Drilling ftuid • Oil, LCM. Hematite Battery packs
Page 71
DOWN HOLE EQUIPMENT FAILURE Following a standardized check lost when !he tool amves insures the light tool has been shipped and was not damaged in transil
PAPERWORK
PHYSICAL CONOm ON
- - -- 1COMPATIBILITY
•
Verily equipment quantities and types
•
Ensure serial/ model numbers on the tool agree with the order lorm, cargo manifest and Inspection report tool
•
locate the operating manual, spec1alonstructoons (d any), settongs and cahbratoon sheet, tool dlmensoons diagram and parts lost
•
Oamaged con1a1ners may tndicate damaged tool
•
MJSsing or damaged parts and spare parts
•
Thread protectors Installed on tools and crossovers
•
Thread and seal1ng shoulder damage
•
Tool bore and other circulating ports are free of debris
•
Explosive I corrosive tools and materials are clearly marked
•
Correct connections size. type and BSR
•
Connection stress relief features match features of the drill string
•
Handling I operabng tools are compatible with rig equipment
•
Plugs I wireline tools will pass through tool
•
Bolt pattern, bolts. ga&kels are correct
•
Functoon test values. Rappers. etc. before running tool in hole
•
Cross-over subs are correct, BSR's are checked
•
Identify and marl< new technology tools
~---------+--~--
OPERATION
UNFAMILIAR /NEW TECHNOLOGY TOOL OPERATING
MANUAL
-------------
Hold a pre·Job safety meeting focused on the safe and proper operation of the tool. If an operator is provided. allow the specialis11o make the presentation Make available to the Oriller, an operations manual for each tool that nequires special operat1ng procedures (i.e .. jars)
AWARENESS / REFRESHERS
Pre-tour safety meetings woth wrrtten Tour Operations Plan, Driller Hand Over Notes with current/next operations section. Discuss operation of unfam1har I new technology tools
TOOL FAILURE REPORT
When tool failure occurs. file a Tool Failure Report to share knowledge of the failure and preventive action taken. A statistical data base can be built with this information
SERVICE/ EQUIPMENT
Inferior service and tools provided by supply companies can account for a substantial number of tool failures. Included In the Tool Failure Report, is a section on supply company performance ratings, An alternative supplier should be considered il ratings indicate high tool failure rate and/or poor service
DRIU. $TitiNG FAILURE
PLANNING
MINIMUM YIELD STRENGTH (MYS)
The minimum load (lbs/sq in of metal} at which plastic deformation of the metal begins
METAL FATIGUE
Accumulated metal damage caused by stress reversals
Fatigue damage is a naturally occurring process that begins when the drill pipe is put into service and accumulates w~h use. Stress cracks form and continue to grow which eventually results in string failure if not detec1ed by inspec1ion
DRILL PIPE FAILURE PREVENTION PLANNING COMPONENT ATIRIBUTES
DESIGN
DEFINITION
EXAMPLE
The d imensions and mechanical properties built into the drill string components. Attributes determine the loads that can be applied
Wall thickness. Yield strength, Toughness, Upset geometry
The designed strength of the drill sting must exceed the loads required to drill the well. Operating below the design limits extends the life or the drill string
Anticipated loads, Correct selection and posmoning of string components, Posting
max-imum tension and torsion limits for tile Driller
INSPECTION
Onsite visual inspection, Examine the drill string components to ensure Electronic inspection based on it meets minimum specifications. Inspections detect wear before it results in a down hole failure drill siring and drilling conditions
OPERATIONS
Improper use, handling and storage of the drill string results in premature s tring failure
Correct connection make·up Calibrating gauges, Operational use and handling practices
SURROUNDINGS
The chemical and mechanical environment in which the drill string is operated. If the
Doglegs, Buckling, Vibrations, Corrosion, High angle wells
S-urroundings. be<»m& hostile , th e ins-pection
frequency should be increased to minimize failures The steps taken to prevent drill s tring 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 Connec1ion Fatigue
•
Torsion
Connection Leak
• Tension I Torsion Combination
Sulfide Stress Cracking
•
Collapse
Spl~
•
Burst
Box
Mechanical Failure of Specialty Tools Welding Failure
Page 73
/JJl/U.. STRING FAII..URlE
DRILL PIPE FATIGUE
DRILL PIPE TUBE FATIGUE FAILURE CAUSE
POINT OF AITACK LOCATION OF FAILURE 16" to 24" from pin and box end
Sharp change in wall thickness between tootjoint and pipe tube
SLIP AREA
16" to 24" from box end
Usi ng one tong, stopping the string with the slips, worn slips and bowl
TUBE MIDDLE
Middle section between pin and box
Contact w~h abrasive formation while rotating causing OD wear
First 5 stands above BHA
Stiffness change from BHA to d rill pipe, possibility of compressional loading with excessive WOB
INTERNAL UPSET
TRANSITION ZONE
FACTORS THAT ACCELERATE DRILL PIPE TUBE FATIGUE •
Slip cuts
•
No transition pipe
•
Doglegs and high angle holes
•
Corrosive mud, oxygen, H,S, carbon dioxide, chlo rides
•
Running bent pipe
•
Running drill pipe in compression
•
Bacl
•
Drill string v•bralions and vertical bouncing
•
E rra tic torque, slip/stick d rilling condition
PREVENTIVE ACTION
• •
Maintain hole angle changes under 3°/ 100'
• • • • • • • • • • • •
Stop pipe, set slips and lower pipe slowly onto slips to prevenl slip cuts
Maintain sufficient levels of corrosion inhibitors and oxygen scavengers
Allow no more than 3' of p ipe length above the slips if possible Always use 2 tongs to make-up and break-out connection Ensure tongs are at 90° angle in two planes when torquing up connections Do not run bent pipe, pipe with deep slip cuts o r corrosion pits Go slow when bacl
Page 74
ORlU.. S YRI~G FAIUI~f: TONGS AT
DRILL PIPE FATIGUE
ANGLE IN 2 PLANES
/ /
/ /
/
/
/
/ /
., _ /
,
.... ....
--
.... LOAD
CELL
CELL
r-----------------------------~~------"I~ S~ECJJQN_~QLQS_~QDE
DRILL PIPE I TOOLJOINT COLOR CODE IDENTIFICATION TOOLJOINT AND DRILL PIPE CLASSIFICATION BANDS
CLASS 1 ....................... 1 WHITE BAND PREMIUM CLASS ........ 2 WHITE BANDS CLASS 2 ....................... 1 YELLOW BAND w a..
0: :;;
CLASS 3 ....................... 1 BLUE BAND CLASS 4 ....................... 1 GREEN BAND
z
0
....z
0 ...., ...J
§ .a
E
SCRAP .......................... 1 RED BAND
0
z
0 0
.... z 0 ...., ...J
§ TOOLJOINT CONDITION STRIPS
SHOP REPAIRABLE ..... 3 RED STRI PS OR SCRAP FIELD REPAIRABLE ..... 3 GREEN STRIPS
Page 75
DRILL STRING FAILURE
DRILL PIPE FATIGUE
I
IDENTIFICATION MARKINGS ON TOOLJOINT STANDARD WEIGHT DRILL PIPE GRADES X, G & S
DRILL PIPE WEIGHT CODE
~~ROVE NEAR BOTTOM!
NOMINAL STD or SIZE WEIGHT TIWALL CODE 1 3-1/2" 13.30 STD
OFTOOWOINT
\ _../'
~~~HAL U ET
~CODE
-
~ \ \ \ ~!
'
GAAOE COOE
..............
~
-
~
WEIGHT
"'-1
MILLED SLOT
THICK WALL DRILL PIPE GRADES X, G & S
15.50
TW
2
14.00
STD
2
15.75
TW
3
4-1/2" 16.60
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
4"
5"
5-1/2"
~~ROVE NEAR TOP OFTOOWOINT
6-518"
I
...,....,
~
'r.
l [!J ~ INTERNAL
\SET
II
DRILL PIPE GRADE CODE E- E75 G - G105 X - X95
~
~
.......
S - S105
IDENTIFICATION MARKINGS ON TOOWOINT DRILL PIPE IDENTIFICATION
Q ~/
-
BENCHMARK
#
:
-::
;: ;;::;;.
'"
AA:uss lllM_N s -p
CODE
uss
- Tooljolnt manufacturer
694
- Date of tool jooning (June, 1994)
N
- Tube manufacture r code (see RP7G)
E
- Drill pipe grade
5I
3
....=;J
Page76
-
DRill STRING fA ....tiRE -
POINT OF ATIACK
BHA FATIGUE
BHA CONNECTION FATIGUE FAILURE CAUSE
PIN NECK
BOTIOMOFTHE BOX
• •
Tension from connection torque and BHA weight
• • • •
Corrosion pitting
Bending load increases neck tension on the outer side of the bending
radius
Bending load applies circumferential stress Box OD wear reduces box strength Corrosion pittlng
FACTORS THAT ACCELERATE BHA CONNECTION FATIGUE • Over or under torquing the connection, under torquing is more common • Doglegs I high angle holes • Corrosion from oxygen. H,S. carbon dioxide. chlorides •
Unstabllized drill collars in compression
•
Large diameter holes or washed out holes
• BHA vibrations and vertical bounclng •
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/slick drilling condaions
PREVENTIVE ACTION •
Maintain hole angle change under 3°/ 100'
•
Maintain sufficient levels of corrosion inhibitors and oxygen scavengers
•
Apply recommended make-up torque with tongs at so• angle in two planes and calibrate tong gauges frequently
•
Correct recommended make-up torque (RMUT) for dope friction factor RMUTeo.= RMUT x Dope Friction Factor
•
Minimize BHA vibration/buckling wah stabilizers. shock subs
•
Inspect the BHA at recommended intervals and after severe eircumstanoes
•
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
ORILL STRING FAILURE
BHA FATIGUE
STRENGTH RATIO (BSR) The r-.tio of box stifrness to pin stlfrnu• After applyong proper torque. bendong strength of connection is balanced when the box silliness os 2.51lmes the pin stiffness A BSR of 2.5 represents a balanced conneC1ion for the average size collar and connee110n type. As collar 00 decreases. BSR should be reduced to compensate for a weaker pin. As collar 00 increases, BSR sho uld be increased to compensate for a stronger pin
1.0
2 .0
BENDING
2 .5
STR E N GTH RATI O
3 .0
3 .5
(BSR)
--·-Page 78
DRILL STRING I=AiLURE
CARE/HANDLING
DRILL CREW 5-SECOND CHECKS DEVELOP A REGULAR HABIT OF DOING 5-SECOND CHECKS THESE CH ECKS CAN BE MADE 0111 THE PIFIE RACK, V-OOOR. RIG FLOOR, WHILE ORi l liNG.ITRIPPING, AND 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
for minimum required OD. Inspect for cracks. eccentric wear (out-of• Caliper roundness). severe tong cuts or unusual damage
•
l ook for small or missing connection bevel
Visually inspect the sealing shoulder a nd 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 the pipe bore for debris, scale. Rabbit all d rill 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 I grade stencils on pin neck I 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 pin
• look for small or missing connection bevel • Check the BHA connections for stress relief g roove feature • look for abnormal connection ID's that are not consistent w ith the string
Page 79
DRIU
CAREIHA N DUNG
ST~JNG
FAJUJRE
DRILL STRING FAILURE WARNING SIGNS CAUTION •
When failure occurs, others may follow
•
Drill string history is unknown
•
Pulling or jarring on stuck pipe
•
Picking up unfamiliar equipment
HIGH RISK
• • • •
Mud corrosion level is high Doglegs a re present Abnormal torque, drag. vibration H19h angle hole
RECOMMENDED DRILLSTRING CARE AND HANDLING PRACTICES DRILLING
TRIPPING
• Keep the mousehote and rathole clean
•
Alternate and record the break on eaCh trip
•
Visually inspect kelly saver sub at frequent intervals
•
Do not let the slips ride the dnll sting
• •
Clean and inspect tong and slip diet at frequent 1ntervals
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 sl1ps when making/breaking
•
AlWays use 2 tongs to make-up and break-out
•
Use correct dope compound for the spectfie connection. Dope threads and shoulder generously
connections. Use a p1pe spinner to &pln.c.tp and back-out conneenons •
Never apply the tongs on the dnll pipe tube
•
If :;:~ conneebon requtrea exc•••Jve bfeak--out
• Do not roll the pin into the box. pick up and re-stab •
Amays use 2 tongs to make-up and break-out connections
torque or the connection has dry or muddy threads on break-out:, clean and visually inspect the pin and box for damage •
• Use a pipe spinner to spin-up and back-oul
• Shoulder damage • Wom or mining bevels • Belled box • Galled or burned threads • Stretched pin • Eccentric box/1ube wear
connections •
Use proper make"up torque for the spec.fic connection
•
Torque connections w~h tongs at go•angle 1n two planes
•
Correct recommended make up torque (RMUT) for dope lriction factor
•
Use a steady pull to torque-up the connection
Keep pipe set back area clean Rinse mud off outside and inside of pipe, Install pipe w1per as
soon as possible •
Do not use a hammer or pipe wrenCh to move stands on the pipe rack. use a pipe lack
•
Do not roll the pin into the box. pick up and re.stab the connection
•
Monitor both make-up and break-out torque, break-out torque should be 80 . 100% of make-up torque
RMUT.,.,. = RMUT x Dope Friction Factor •
watch for these signs on trips:
Pag e 80
DRILLING JARS
DRILLING JAR ADVANTAGE
A drilling tool designed to deliver high impact "hammef' blows to the stuck drill string Higher probability of recovery with immediate and cof18cf application of jar blows
A OPEN
INNER MANDREL-
8"
I COCKE D
8"
OUTER BARREL
V cLoseo SPLINE DRIVE
_ LATCH MECHANISM
LOWER SEAL
- WASH PIPE
DRILLING JARS PUMP OPEN FORCE (POF) Force of circulatong or trapped pressure pushing the jar to the open position
PRESSURE DROP = 2001 psi WASHPIPE AREA = x10 sq in
P/0FORCE : 20,000 lbs
BOTIOMAREA 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 1mposs11>fa to cock. Slow /stop pumps or bleed trapped pressure before cocking
COCKING FROM
Makes the jar 9&sl6r to cock
[cLOSE POSITION POF AFFECT ON MECHANICAL JAR BLOW ADVANTAGE DISADVANTAGE
Less stnng tensoon requred for an up-jar blow More set down weight required lor a down-jar blow. Slow I stop pumps or bleed trapped pressure when janing down
POF AFFECT ON HYDRAULIC JAR BLOW ADVANTAGE DISADVANTAGE
lnlensifies the up-jar blow Dampens the down-jar blow. Slow /stop pumps or bleed • trapped pressure when janing down
Page 82
DRILLING JARS COCKING THE JAR MINIMUM WEIGHT INDICATOR READING TO COCK THE MECH I HYD JAR COCKING FROM OPEN POSinON
COCKING FROM CLOSED POSITION Last recorded pick-up wt - BHA wt below jar + Internal jar friction Wt. Indicator load
=
= 330,000 Lbs = 30.000 Lbs = 10,000 Lbs
= 310.000 Lbs
POF will ASSIST cocking the jar
Last recorded slack-off wt = 330,000 Lbs - BHA wt below jar = 30,000 Lbs - Internal jar friction = 10,000 Lbs - Pum~ O(len force = 20.000 Lbs = W . Indicator I Ui = 270 000 Lbs 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
CALC ULATING TRIP LOAD MECHANICAL JAR UP.JARBLOW
DOWN-JAR BLOW
= = =
Last recorded slack-off wt 330,000 Lbs 30,000 Lbs - BHA wt below jar - On-jar trip load setting = 40,000 Lbs - Pum~n force 20,000 Lbs WI. Indicator load = 240,000 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 Last recorded pick-up wt 30,000 Lbs - BHA wt below jar + Up-jar trip load setting = 80,000 Lbs - Pum(l Qi!en force 20,000 Lbs = Wt. Indicator load 360,000 Lbs After cocking the jar, pump pressure can be increasec to reduce pick-up weight required to trip the jar
= = =
HYDRAULIC JAR UP.JARBLOW
DOWN-JAR BLOW
= = =
Last recorded slack-off wt 330,000 Lbs - BHA wt belOW jar = 30,000 Lbs 50,000 Lbs - OESIIREO• trip load - Pumf! Of!en force = 20,000 Lbs Wt. Indicator load 230,000 Lbs Slow down or stop the pumps or bleed trapped pressure to reduce the slack-off weight required to trip the jar
=
Last recorded pick-up wt - BHA wt below jar + DESIRED" trip load
- Pume Oe!n fgrce
=Wt. Indicator load
= 330,000 Lbs
= 30,000 Lbs = 80,000 Lbs = 20,000 Lbs
= 360,000 Lbs
After cocking the jar, pump pressure can be Increased to reduce pick-up weight required to trip the jar
• DESIRED · The trip load selected by the jar operator
TRIPPING THE JAR MECHANICAL JAR DOWN-JAR BLOW
UP.JARBLOW
•
After cocking the jar, slack off to the calculated weight indicator load
•
No delay time Is required, the latch will trip w hen the preset 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, slack off additional weight (10,000 to 20, 000 lbs)
• • •
After cocking the jar. pick up to the calculated weight i ndicator load No delay time is required. the latch will trip when the preset trip load is applied to the jar If the jar still does not trip, increase circulating
pressure to maximum to increase the pump open force. Do not apply trapped pressure
•
Page 83
If the jar does not trip, pick up additional weight (10,000 to 20.000 lbs)
DRILLING JARS HYDRAUUC JAR DOWN-JAR BLOW
UP..JARBLOW
• After cocking the jar, slack-off to the calculated weight indicator load
• After cocking the jar, pick-up to the calculated weight indicator load
• Lock down the brake and wait for the jar time delay to elapse. See your jar manual (30 · 60 sec short cycle, 2 • 8 min long cycle)
• Lock down the brake and wait for the jar time delay to elapse. See your jar manual (30 • 60 sec short cycle. 2 • 8 min long cycle)
• If the jar does not trip, stop pumping or bleed trapped pressure. Recock the jar and apply trip load
• If the jar does not trip, circulate at max rate and allow additional time {do not apply trapped pressure)
• If the jar still does not trip, slack-off more • If the jar still does not trip, stop pumping weight and allow more time and recock the j ar and apply trip load
(31
WEIGHTIS SLACKED
Off
I~
(~
OflllSTRING CONTRACTS
BIIAMASSIS A~CEL£RATED
/
BY GRAVITY
(6) IIHA MASS IS
ACCEI.WltD
(4)
JAR (2) JAR
LATCH TRIPS (2) JAR
COCKS (6)
IIIPACT IS
(4) JAR
LATCH TRIPS (7)
IIIPACTIS
Page 84
DRILLING JARS . lA~ ~~~~
REASONS FOR JAR NOT TRIPPING HYDRAULIC JAR MECHANICAL JAR • Jar not cocked
•
Jar not cocked
• Stuck above jar
•
Not waiting long enough
• Jar failure
•
Stuck above jar
• Pump open force not considered
•
Jar failure
• Pick-up /slack-off weight incorrect
•
Pump open force not considered
• Unknown /incorrect trip load setting
•
Pick-up /slack-off weight incorrect
• Excessive hole drag
•
Excessive hole drag
• Right-hand torque trapped in torque sensitive jar
.l A~
LIA"'"''"'"
JAR HANDLING RECOMMENDATIONS • If a service connection is found loose, call the shop for recommended torque. Do not use tooljoint torque on these connections
• Do not tie the chain hoist. apply the tongs or set the slips on the exposed polished section of the inner mandrel • A mechanical jar is shipped in the oocked position. Run the jar in the extended or cocked position • Rack a mechanical jar in lhe derrick in the cocked position at any position in the stand • A hydraulic jar is shipped with a safety clamp on the inner mandrel. The jar mu&t be run in the open position
• Rack a hydraulic jar in the derrick with the safety clamp at any position In the stand
DRILLING ACCELERATOR An energy storing device designed to opti mize the drilling jar assembly for maximum up and down jar-blow i ntensity
ADVANTAGES
•
Allows optimum jar placement
•
Intensifies the jar blow
•
Protects the drill string and rig surface equipment from h igh impact loads
•
Compensates for insufficient d r ill string stretch in shallow holes
•
Compensates for excessive dra g in high angle holes
Page 85
DRILLING JARS
INNER MANDREL OUTER
BARREL SPLIN E DRIVE NITORGEN NITROGEN (2000 psi) --
BY APPLIED OVERPULL
LOWER SEAL WASH
PIPE BHA MASS ACCELERATED
1 WEIGHT SLACKED
OFF
3 ~ OVERPULL APPLIED
4 ACCELERATOR STROKES OUT
2 JAR COCKS
6 BHA ACCELERATED
5
JAR LATCH TRIPS
7
JAR BLOW DELIVERED
DRILLING JARS BASIC JARRING RULES STRING STA TIC When sticking occurred
~>>
JA R DOWN
STRING MOVING UP when sticking occurred
~>>
JAR DOWN
STRING M OVING DOWN 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 ASSEMBUES (< 60 HOLE ANGLE) JAR ASSEMBLY
JAR I ACCELERATOR ASSEMBLY
W EIG H T FOR UP AND DOWN JAR BLOW
WEIGHT FOR DOWN
EQUAL TO D OWN-TRIP LOAD
1.2+ OF DOWN-TRIP
JAR BLOW
LOAD
WEIGHT FOR UP J AR BLOW
0 .2 OF UPTRIP LOAD
Page 87
DP
DRILLING JAR I ACCELERATOR PLACEMENT WORKSHEET (0~- 60' iiiiAT: 0
Hole Angle At BHA: _ _
BF_ _ X AF
X 93
= Wt Factor: _ __
1. 45'< hole angle, select a mechanical jar (non-torq sensitive, highest pump-open force, longest jar stroke). Select highest recommended trip load settings (do not exceed 60% of string over-pull limit).
Down· Trip Load: -
Up-Trip Load:
-
-
--
> 45" hole angle, select a hydraulic jar (highest pump-open force, longest jar stroke). Jar Make /Type: - - - - -- - - - - - - - - - :MECH DOWNJAR STANDS:
2. A drilling accelerator (recommended) increases jar impact by 30% • 50%. Match the jar and accelerator 00 to the 00 of the BHA section the tool is placed in. Jar OD: - - - - -
..
"U
STANDS
ABOVE JAR:
: HYD
tl
::0
Accelerator OD: - - - - -
;:::: ,....
3. Do not run stabilizers / reamers above the jar. Place the jar /accelerator above or below the neutral zone.
HWOP
ACCElERATOR
tl2
•......
UPJAR STANDS
Neu Zone,= WOB
X 1. 15 + Lbsift_ _ + Wt Factor
=
Stands from bit
Neu Zone ,: WOB
X 0.85 + Lbs/ft_ _ + W I Factor
=
Stands from bit
1
~
(j)
~
HWOP
::0 (/)
1.
BELOWJAR WEIGHT:
If key seat potential is high, consider a string reamer. Do not place jar /accelerator in the neutral zone. Place a minimum BHA weight above the jar equal to 1.2 times the down-jar trip load ( On-Jar Stds). Dn-TripLoad
X 1.2 +lbs/Ft_ _ +WtFactor _ _
= _ _ Dn-JarStds
2. Place a BHA weight of 0.2 times the up-trip load between the jar and accelerator (Up-Jar Stds). STANDS:
Up-Trip Load
BELOW JAR
Wt
X 0.2 + Lbs/Ft__ + Wt Factor__ = _ _ Up-Jar Stds DC
If an accelerator is not used, position the jar for a 70% probability of down-ja rring. Place the jar (above or below the neutral zone) with a BHA weight above the jar equal to the down-trip load. WOB:
l
STANDS:_ _
On-Trip Load
+ Lbs/Ft _ _
+ WtFactor _ _ = __ StdsAboveJar
l wos:
DRILLING JAR I ACCELERATOR PLACEMENT WORKSHEET(> 60u) Hole size:
BHA II:
RECOMMENDATIONS
Select a hydraulic jar (highest pump-oJ;en force. longest jar stroke).
Jar Make / Model: - - - - - - - - - - - - - - -
' · A DOUBLE-ACnNG drilling accelerator is required. Match the jar and accelerator OD to the OD of the HWDP. Accelerator OD: -
Jar OD: - - - - -
----
2 . Place the jar at the top of the steerable assembly. Place HWDP above the jar equal to 0.2 of the maximum down-jar trip load.
On-Trip Load DOWNJAR STANDS:
,..
"'..
X 0.2 + Lbs/Ft + 93 =
Jarring Stands
3. Place the accelerator above the jarring stands. Run standard-wall drill piJ:e from the accelerator to the 60° hole angle section (considering the bit at ir s maximum an:icipated depth). 4.
Run collars / HWDP above the so• hole angle to provide weight for down-jar trip load (plus estimated dow n-drag between the so• hole angle and the accelerator). (Dn.Jar Trip Load
+ Hole Drag
+ LbsiFt
[ ~L'?s:'.':~~~~:-:; .':~c:i.:~~~ ~~~~!A J
: BF
: AF
+ 93 = ___On-Jar Stds
~ ~e5.~-~~~C::fr!:Ol~~~
rr-
~
(j')
CD
0
0
::0
~
s. Consult with lhe jar service company if angle build rate exceeds 6 11oo·
~
Standard wall OP: Stands JARRING STANDS:
DOUBLE-ACTING ACCELERATOR
BIT AT MAXIMUM ANTICIPATED DEPTH
WELL CONTROL
l.~
The control of formation fluid flow (kick) into the wellbore
THREE PHASES OF WELL CONTROL .
PRIMARY First Line Of Defense
Control of kicks with hydrostatic pressure (HSP) only
Drill to total depth without a well control event
SECONDARY Second Line Of Defense
Control of kicks with HSP assisted by blowout preventer equipment
Safely kill the kick without the loss of circulation
TERTIARY Third Line Of Defense
An underground blowout
Avoid a surface blowout. Regain primary well control
The ultimate goal of well pressure control is to prevent a surface blowout DDIUADV
. ,.
, PRIMARY WELL CONTROL
IHURG!I'iitOS_f'REIIURE
I''
~ o;
PPG
The pressure developed by the height and density of a non-moving fluid column
=Pounds per gallon fluid density
0.052 = PPG to PSI/FT conversion factor TVD = True vertical depth (FT) HSPPSI
=MUDpPG X = 10.0
X
.052 X TV(\,T
.052
X
10,000
=5200 psi HSP 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
WELL CONTROL
PRIMARY
The piston affect of upward string movement causing a decrease in wellbore pressure which can induce a kick
SWAB
The piston affect of down- Maximum surge pressure occurs at the bit and is equally imposed to the ward string movement bottom of the wellbore causing an increase in wellbore pressure which As string motion is started, additional can result in loss of surge pressure is imposed to break circulation the gel strength of the mud and accelerate the mud column
SURGE
The pump pressure required to break the gel strength of the mud and accelerate the mud column
PUMP SURGE
w
a:
~
As string motion is started, additional surge pressure is imposed to break the gel strength of the mud and accelerate the mud column
The hydrostatic pressure overbalance overbalance pressure (i.e., 300 - 500 is more often dictated by hole psi) to compensate for instability (i.e., 800 - 2000 psi) swab pressure
MARGIN
l
Maximum swab pressure occurs at the bit and is equally imposed to the bottom of the well bore
Pump surge pressure to break circulation may be greater than the normal circulating annulus friction pressure
STEADY CIRCULATION
l!!
~ STEAOY SPEED
~<
a:
0..
Page 92
WELL CONTROL
PRIMARY
The mud weight equivalent to the sum of hydrostatic and annulus friction pressures at a true vertical depth of interest
ECD PPII
• ( Ann Frlc..., ) + MWPPII TVDFt X .062
2500'
= (10,:X .052 ) + 10·0 = 10.8ppg ECD
5000'
7500'
10,ooo·L-.,--------,----=:::~ 0
2 3 4 5 6 PRESSURE (1000 pal)--+
1
Built-in safety factor during a kick killing
Penetration rate decreases as ECD
operation
increases
Safety factor if circulating near or slightly under balance to formation
Increases potential for lost circulation , differential sticking, wellbore instability
Indicates the next casing depth to maintain well control safety Input to risk analysis if decision is made to drill ahead
Page 93
PRIMARY
WELL CONTROL
Monitor the well for signs of changing formation pressure
Driller Mud Logger Shaker Man
Geologist Drilling Engineer Company Rep
Ensure mud weight is correct before drilling into known high or low pressure zones
Company Rep Mud Logger Toolpusher
Geologist Drilling Engineer
Ensure means of disposing of contaminated nuids to avoid contaminating the mud system
Mud Engineer Shaker Man Derrick Man
Driller Toolpusher Company Rep
Shaker Man Derrick Man
Driller Mud Engineer
Ensure proper mud weight is used to fill the hole during trips Maintain pit valve seals to avoid accidental dilution Maintain degasser capacity to handle full returns
Ensure proper hole fill during trips Use a calibrated trip tank. Appoint a dedicated trip tank man. Record hole volumes during round trip If correct fill-up is not taken (swabbing indicated), now check the well. If not nowing, return to bottom and circulate bottoms up
Driller Mud Logger Trip Tank Man
Company Rep Drilling Engineer Toolpusher
If correct displacement volume does not return while tripping in (lost circulation indicated), stop tripping and observe the well. If circulation is lost, pump fluid down the annulus. If the well is nowing, shut-in immediately Maintain mud box seals, ensure drain is plumbed to the trip tank or annulus if filling with pump strokes
AID Floor Men
Company Rep Toolpusher
Maintain hole full during non-circulating operations
AID Driller
Company Rep Tool pusher
Pag e 94
WELL CONTROL
The loss of hydrostatic pressure control of formation fluid flow into the well bore The control of formation fluid flow by the use of hydrostatic pressure ASSISTED by blowout preventer equipment
PERMEABLE ZONE IS DRILLED WITH MUD WT INSUFFICIENT TO CONTROL FORMATION PRES§URE
PROGNOSED ABNORMAL FORMATION PRESSURE
GEOLOGIST I MUD LOGGER ABNORMAL PRESSURE TREND CHANGES TORQUE/DRAG INCREASE DRILLING BREAK
POSITION DRILL STRING FOR SHUT-IN
ADJUST MUD WEIGHT PRIOR TO DRILLING KNOWN ABNORMAL PRESSURED ZONE
Page 95
WELL CONTROL
CAUSE: HYDROSTATIC PRESSURE IS REDUCED BELOW THE FORMATION PRESSURE OF A PERMEABLE ZONE (SWABBING. LOST CIRCULATION. LIGHT
PROGNOSED LOSS CIRCULATION POTENTIAL HIGH MUD WEIGHTS INCREASE POTENTIAL FOR SWABBING
A kick was swabbed in & the drill string stripped to bottom
INDICATIONS: LOSS OF CIRCULATION DURING ANY OPERATION HOLE NOT TAKING CORRECT FILL-UP DURING TRIP
- --.,.j =--::::-.. . .:=
WATER/GAS-CUT MUD WH ILE CIRCULATING WELL FLOWING. PIT GAIN
FIRST ACTION: SOUND KICK ALARM
~ :::==·====:-::-:-=-j-'
!•
POSITION DRILL STRING FOR SHUTIN, STOP CIRCULATION
=:=·:::::::=:==~
SHUT-IN THE WELL
MAINTAIN PROPER MUD WEIGHT KEEP HOLE FULL PROPER HOLE FILL-UP ON TRIPS
·~~==:;:s::::~ MINIMIZE LOST CIRCULATION ~
POTENTIAL
Page 96
"'0 "'
V>
KICK ~$1GNS
C1I,ITlMGS Rfl\JRH, ~ R.OW FORMATION
PRESSURE PRWCTION
..
.,"0
•.... "'
~
I"" I""
~+"'
CONFIRM GEOlOGICAl
r?/
PLAH
,.,,.-_{i
....
·~·-")'
(,o+Q
f<,.,
0~
,;>
~.#
.o.· _,v
/'
0
<::
i1
flo+'
~~0
. .q~
0
.T
~
EVACUATION
~.-!
""- ......
IIIECHAHICAL UMITS, RIG I VESSEL CONDITIONS
J!.;,qq <;
V>
STANDBY VESSEL
m 0 0
z ~ ~
~CON DARY
WELL CONTROL
QRILL!NG KICKS
CAUIES'OF-ICH:KaWHLB:DRII fiND '--~ ;,_,.~ UNDER BALANCE lOCK INDUCED IGCK ~. ", Drilling into a permeable zone with a mud weight insufficient to control formation pressure
Lost circulation Light mud pumped down hole Swabbing while worlling the string/ making connection Core volume gas cut mud
LOGGER TREN DS d exponent decrease. Shale density decrease, Splintery shale INDICATE FP cuttings, Connection /background INCREASE gas increase Indicates a new formation exposed DRILLIN G BREAK to the well. Under balance kicks are usually preceded by an abrupt ROP change, increase or WELL FLOW
PIT VOLUME
Kick fluids displace mud from the 1WE~!Ibore increasing the return flow 1:-;n,aKo~r causing well flow with pumps off 1n o,.,;,,., kick fluids flow into the wellbore volume addition is detected by pit volume totalizer (PVT) Lower density kick fluids decrease Driller annulus hydrostatic pressure allowing the drill string mud to Mud Logger !,:;'~~;~~~ U-tube into the annulus
Page 98
WELL CONTROL
DRILLING KICKS
SECONDARY
INDJ.CAIIONS - -
INDICATIONS OF INDUCED KICKS LOUO,-.UD WIEIGHT-
.li ~'MUD PUMPED, SWABBED GAS , CORE GASl 1 :~~~- NOTIFY
NOTE
INDICAnoN
PUMP PRES SURE Lower density kick fluid decreases Toolpusher Driller DECREASE/SPM annulus hydrostatic pressure Derrick Man Mud Logger allowing the drill string m ud INCREASE Mud Eng column to U-tube into the annulus
WELL FLOW
PIT VOLUME GAIN
Kick fluids displace mud from the wellbore increasing return flow or causing well flow w ith pumps off
Driller Mud Logger Shaker Man Derrick Man
Drl Crew Co Rep Toolpusher Mud Eng
As kick fluids flow into the wellbore, the voulume addition is detected by the pit volume totalizer (PVT)
Driller Mud Logger Shaker Man Derrick Man
Drl Crew Co Rep Toolpusher Mud Eng
LOSS OF COLUMN HEIGHT (TOTAL LOSS OF CIRCULAnoN, NOT KEEPING HOLE FULL) INDICAnoN
NOTE
MUD COLUMN LEVEL DECREASE
Loss of hydrostatic pressure may induce a kick
SIBILITV
NOTIFY
Driller Mud Logger Shaker Man Derrick Man
Drl Crew Co Rep Toolpusher Mud Eno
FLOW CHECK GUIDE .INES WHILE DRIWNG
_SIJ
CESTACK
SUB SEA STACK
• Drill 3 to 5 feet into the break, observe for flow
• Drill 3 to 5 feet into the break, observe for flow
• If flow is detected, initiate shut-in
• If flow is detected, initiate shut-in procedure
procedure
• Raise the kelly /top drive to the shut- • Raise the kelly /top drive to the shutin position
•
in position
Stop circulation and observe well for flow 5 to 10 minutes
• Maintain slow rotation to prevent sticking
• If flow is detected, initiate shut-in procedure
• Stop circulation, line-up trip tank and observe well for flow 5 to 10 minutes • Maintain slow rotation to prevent sticking • If flow is detected, initiate shut-in procedure
Page 99
WELL CONTROL
SECONDARY
.·
DRILLING KICKS
DIWRTER GUIDILINI!8 WtR.E DRilliNG
auag&-...,
•
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 full circulation
•
Maintain full circulation
•
Open down-wind diverter line and close the diverter
•
Prepare to abandon the location
•
• Monitor the sea surface for gas. MovE the rig up-wind of surfacing gas Open pump suctions to the heavy mud reserves and pump at maximum • Fill pits with sea water rate
•
Build additional heavy mud volume
•
•
Prepare to abandon the rig
--
Gas zone depletion may take several hours or days
~ QUIDPI
• Sound the kick alarm
Continue pumping the heaviest fluid available at maximum rate
111!8 wta.E DRill . . SUB 8I!A STACK • Sound the kick alarm
• Raise the kelly flop drive to the shut- • Raise the kelly /top drive to the shutin position in position • Stop circulation
• Stop circulation
• Open the choke line valve
• Open the choke line valve
• Close the upper pipe rams or annular preventer
• Close the upper annular preventer
• Record SIDPP and SICP every 2 minutes • If necessary, adjust annular preventer closing pressure for stabilized SICP
• Record SIDPP and SICP every 2 minutes • If necessary, adjust annular preventer closing pressure for stabilized SICP
Page100
WELL CONTROL
• Occurs only while drilling • Abnormal formation pressure produces an under balance kick • SIDPP is some value above standpipe hydrostatic pressure • Can occur during any open hole operation INDUCED KICK
• All formation pressure classifications can produce an induced kick • SIDPP is equal to standpipe hydrostatic pressure
WAIT & WEIGHT METHOD CIRCULATION METHOD (DRILLER'S) WITH BALANCE KILL MUD WEIGHT WITH PRESENT MUD WEIGHT
• A constant bottom hole pressure method to prevent second kicks
•
A constant bottom hole pressure method to prevent second kicks
• Minimizes kill pressures imposed to the wellbore and equipment
•
Minimizes kill pressures imposed to the wellbore and equipment
• Kills the kick in one complete circulation
•
Kills the kick in one bottoms up circulation
CIRCULATION METHOD (DRILLER'S) WAIT & WEIGHT METHOD WITH PRESENT MUD WEIGHT WITH BALANCE KILL MUD WEIGHT AS GAS REACHES SHOE AT SHUT-IN
If shut-in pressures are contained without formation fracture, the probability of a successful kill is greater than 90%
The depth of the influx at shut-in is seldom known. Actual bit-to-shoe strokes cannot be determined. Follow Circulation Method kill procedure
Page 101
Cl)
~
0
z
,.. 0
~ ASSIST MUO ENGINEER
ASSIST AS NEEDED
~
,..... ,..... "0
• "'•
.....
/
0
,,o~
,/0{1-
'~ ..
#
~
i10
Ov,.
"'
~
~ OPERATIONAL PUN, MECHANICAL REQUIREMENT:
. . . . . .<
(')
IIECHANICALLMTS, RIG / 1/ESSEL CONDmONS
,.....
EVACUATION
READINESS
l STANDBY VESSEL
"'0 "' Cl)
WELL CONTROL
KILL METHODS
...
·~.,.~ ,:;;;:??!:?'~~::. L_._ ~ I.-!d ___ _.:_1 .t. ,___, :...:~... • ._ -
SECONDARY
._...
:·· -: •
.
'
•
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 shutin value plus 50 - 100 psi safety factor
•
Calculate kill mud weight (KMW)
•
Over balance in the KMW or additional choke pressure is not recommended or required for a safe kill operation
• •
Construct a drill pipe pressure schedule When preparations are complete , start the kill operation Surface Stack - Hold casing pressure at shut-in value while increasing the pump to kill rate Sub Sea Stack - Hold kill line pressure at shut-in value while increasing pump to kill rate
•
Hold pump speed at kill pump rate (KPR) and adjust the choke for proper drill pipe pressure schedule
•
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 gas trapped in the BOP stack, displace riser with KMW
•
Open the BOP and check the well for flow. Condition the mud system,
•
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 shutin value plus 50 - 100 psi safety factor
•
An increase in the 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 increasing the pump to kill rate Sub Sea Stack - Hold kill line pressure at shut-in value while increasing the pump to kill rate
• •
With pump at kill pump rate, record the observed circulating drill pipe pressure
• •
Sub Sea Stack - Remove gas trapped in the BOP stack
Hold pump speed at kill pump rate and adjust the choke to maintain the recorded drill pipe pressure value until bottoms up strokes are pumped Check the well for flow, condition the mud system
Page 103
I
SECONDARY
WELL CONTROL
KICKS
o
Close the lower pipe rams to isolate the wellbore from the stack gas clearing operation
o
Open the kill line fail-safe valves. U-tubing pressure from kill mud weight (KMW) in choke line will be observed if choke line fluid density is greater
o
Displace the kill line with KMW pumping down the choke line and return through the kill line - Hold kill line pressure constant and increase pump to kill rate . Record circulating pressure • Hold pump speed constant and adjust choke to hold circulating pressure constant until KMW returns
0
Displace only the choke line with water. Allow pump pressure to increase as water is pumped
0
Close the kill line fail-safe valves
0
Open the choke line completely to allow the trapped gas to expand into the choke line
0
Line up the trip tank to maintain the riser full
0
When expanding flow from the choke line stops, open the annular preventer completely to allow the riser to U-tube into the choke line
0
When U-tubing stops, close the choke line fail-safe valves
0
Close the diverter and open the down-wind overboard line or flow line degasser
0
Open the kill line fail-safe valves and displace the riser with KMW. Displace choke line with KMW
0
Open the lower rams and check the well for flow
Page 104
WELL CONTROL
TRIPPING KICKS -~
"'"'-':-
i<- .~.o;,.
'
SECONDARY
CAUSES.OF KICKS WHILE TRIPPING
ionty fnduced1ck:ka a.n occur during a tripping operation Swabbing (#1 cause of kicks) Improper hole fill procedure Loss of circulation Filling the hole with light fluid Weighting material sag
. .
~--:-"-
IIUicA110N
INDICATIONS OF INDUCED KICKS ~~~~~NOTE
NOTIFY
The volume of steel pulled from Mud Eng HOLE NOT TAKING the hole is greater than the mud Driller volume required to fill the hole Trip Tank Man Co Rep CORRECT FILL-UP Mud Logger Toolpusher Overpull usually associated w ith swabbing
WELL FLOW
PIT VOLUME GAIN
Kick fluids displace mud from the well bore causing well flow with pumps off
Drilling Crew Driller Mud Eng Trip Tank Man Co Rep Primary well control is lost when Mud Logger Toolpusher the well begins to flow
As kick fluids flow into the wellDriller bore, the volume addition is Trip Tank Man detected by the pit volume Mud Logger totalizer (PVT)
Drilling Crew Mud Eng Co Rep Toolpusher
• 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
• Observe the well for flow 5 - 10 minutes
• Line-up the trip tank and observe the well for flow 5 - 10 minutes
• Maintain slow rotation to prevent sticking
• Maintain slow rotation to prevent sticking
• If flow is detected, initiate shut-i n procedure
• If flow is detected, initi ate shut-in procedure
Page 105
WELL CONTROL
SECONDARY
TRIPPING KICKS
DIVERTER GUIDBLINU WHILE TRPPIIIG .. -.SI!AjrACK SURFACE STACK
' .
•
Sound the kick alarm
•
•
Set the top tooljoint on the slips
• Set the top tooljoint on the slips
Sound the kick alarm
• Install and close the full open safety • Install and close the full open safety valve
valve
• Open down wind diverter line and • Make-up kelly /top drive and open safety valve
•
• Make-up top drive /kelly and pump the heaviest available fluid at maximum rate
close the diverter
Open pump suctions to the heavy mud reserves and pump at maximum rate
•
Build additional heavy mud volume
•
Prepare to abandon the rig
• •
Prepare to abandon the location
•
Fill pits /tanks with sea water
•
Continue pumping the heaviest fluid available at maximum rate
Monitor the sea surface for gas. Move rig up wind of surfacing gas
Gas zone dep letion may take several h ours or days
SHUT-IN GUIDE' ltEI WilLE TRIIPING r-----'~""'CE STACK •
Sound the kick alarm
•
Set the top tooljoint on the slips
SUB SEA_STACK ~-·--"'1
! • Sound the kick alarm •
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 choke line valves
•
Open the upper choke line fail-safe valves
• Close the annular preventer with 1500 psi closing pressure
•
Close the upper annular preventer w ith 1500 psi closing pressure
•
Record SICP every 2 minutes
•
Adjust annular preventer closing pressure to stabilized SICP
•
Record SICP every 2 minutes
• Adjust annular preventer closing pressure to stabilized SICP
Maintain string movement to preven sticking • '-------'-----------! •
Maintain string movement to preven sticking
Page106
WELL CONTROL
TRIPPING KICKS
KICK
SECONDARY
EVALUATE 'fttiiE:OFF BOMOM KICK COiaTIQN ' •... :.::: .. ...... .. iDII. :._ ~
~
.._
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
NO PIPE IN HOLE
The drill string is pulled out of the hole before the kick is detected
STRIP AND BLEED Strip the drill string to bottom and kill the kick using the Circulation Method with present mud weight
SNUBBING Snub the drill string into the wellbore until string weight is sufficient for stripping operation
J
SNUBBING Snub the drill string into the wellbore until string weight is sufficient for stripping operation
IF SIIWPING OR INUB.JG. NOT POtii.LB U.,
anJCK......,
VOLUMETRIC METHOD VOLUME TRIC METHOD VOL UMETRIC METHOD Allow the gas to migrate above the bit. Kill the kick us1ng 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
Allow the gas to migrate to surface. Kill the kick using the Dynamic Lubricate and Bleed procedure
IF THE GAS ..GRATES LAST RESORT OP"RRN 'IOIURMCE HEAVY M UD CAP Circulate kill mud weight of sufficient density to kill the casing pressure Open the BOP and run to bottom
l
Kill the kick using the Circulation Method with present mud weight
LUBRICATE AND BLEED Pump present mud weight across the wellhead, th rough the choke and back to a small calibrated pit
B ULLHEAD Use only under special conditions Pump present mud weight to fracture pressure and inject influx into formation
Decrease casing pressure by PSIIBBL equivalent per If shoe fractures first. an under ground blowout will barrel of mud loss in the occur pit
Page107
I
WELL CONTROL
SECONDARY
KICKS
Calculate the maximum allowable surface pressure (MASP) to avoid formation fractur MASP
=(Fracppa •
M udPPG ) X .052 X TVOshoe
• Calculate the maximum casing pressure limit (MCPL) to determine when to stop stripping and circulate a portion of the influx out of the wellbore M CPL
=MASP
x .8
• Calculate displacement volume per stand of pipe stripped into the hole Bblslstd =(Pipe disp + cap) X Stand Length Route the returns from the choke manifold to the trip tank. Sub Sea Stack: If necessary, displace the choke line with present mud weight • Adjust the annular preventer closing pressure for stripping. Route the lubricating mud volume to the trip tank • Apply 100 - 200 psi safety factor. Hold the choke closed and strip 1 • 2 stands until safety factor is reached (SICP + SF). If necessary, bleed SICP to safety factor value Strip in a stand and alternately bleed out the bbllstd volume. SICP w ill return to the safety factor value if the bit Is above the influx SICP will increase as the BHA enters the influx and decrease as the BHA moves below the influx. Continue stripping to bottom. Use the Circulation Method with present mud weight to kill the kick
11-
____________ .MAQP_::..11.00..P~L------ ------------
1(}
Overbalance restored
o g.
MCPL = 880 si
as bit reaches bottom
~ ----------------------~----------------~-71 >< 8
-
·-
~
/!
••
// L.,./
7-
Ol
..../j
... L-· ........
-1
.~
.•'
..
L.---··-..
'\
~
/ •
.......1 :'
t
.~
. -- . , __....
Bit below 1'nflu.x
C 6· .....~-·· ../ ·'-"'~ : .-.-·: 'iii
···"'j
...·1I
·' -. - -_:._.-.-----
••••
~ ' ••.•
•' ....•••
•..
Influx pushed up
h0 Ie bY pipe · d' ISp
ftl
() 5-
BHA enters influx
-
Bit on
bottom~
4 -~----.----,r----,-----.----~----~----~~~~
6
7
8
9
10
11
12
13
14
Stands Stripped If maximum casing pressure limit Is reached (MCPL). stop stripping operation. Use the Circulation Method with present mud weight and 100 -200 psi safety factor to circulate a portion of the influx out. Continue stripping to bottom
Page108
WELL CONTROL
KICKS
•
'
_-'"":"'>'
•*
-r-~r
r
.
~ - -
-
• Route returns from the choke manifold to the trip tank • Calculate the maximum allowable surface pressure (MASP) to avoid formation fracture MASP = (Fracppg- Mud ppg) X 0.052 X TVDshoe • Calculate the required barrels to bleed (8/BBLs) before allowing casing pressure to increase by 50 psi B/BBLs = Bbls/Ft 0 pen hole
X
50+ Mud ppg + 0.052
• Hold the choke closed and allow the migrating gas to increase casing pressure by a 100 - 200 psi safety factor. If accessible, drill pipe pressure will show an equal increase • When calculated casing pressure is reached (SICP + SF), bleed mud through the choke to maintain casing pressure • After bleeding the calculated barrels (8/BBLs), hold the choke closed and allow casing pressure to increase by 50 psi • When calculated casing pressure is reached (SICP + 50 psi), bleed mud through the choke to maintain the new casing pressure • If shut-in off bottom, continue repeating this procedure until shutin pressures indicate the gas has migrated above the bit • Use the Circulation Method with present mud weight and 100200 psi safety factor to circulate the gas out of the hole • If shut-in with no pipe in the hole, continue this procedure until the gas migrates to surface. • Use the Lubricate & Bleed guidelines to remove the gas 11·
_ _ __ _ _ _ _ _ _ _ ll/IA9.,P _
; ..l.:!.Q.Q..Q§.i ______________ _
1().
. ii 6 · en
c:: s •.
·=
(..) 4 ·
3-
Page 109
WELL CONTROL
SECONDARY
KICKS
• 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/Ftcsg x
50
+
Mud ppg + 0.052
• Construct a schedule for barrels lubricated into the well bore versus casing pressure decrease. A 50 psi safety factor is recommended When preparations are complete. zero the pit level indicator and start the kill operation: - Adjust the choke to hold casing pressure at it's shut-in value while increasing the pump speed - Increase pump speed to 1 - 2 barrels per minute. Maintain SPM constant during the kill procedure • Apply a 50 psi safety factor. Adjust the choke to maintain casing pressure at it's shut-in value until the pit level decreases by the LUB BBLs • Continue holding the pump speed constant and allow the casing pressure to decrease. As the lubricated mud volume increases hydrostatic pressure, casing pressure will decrease accordingly
8-
Total LUB _ .,;_ BBLs ~
7- .........
~
6-
0 0
.... 5)( ._.
·-1/1 4-
' , '
/'
.....
Calculated Cag Prenure
··..... ··········
Q.
Cl 3-
c:
Ill
"' 2-
0
10-~~--~~---r--~~--~--r-~--~--~-r--~~
o
15
3o
45
60
75
90
105 1io 135 1so
165 1ao
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
An underground diversion of high pressure kick fluids Methods employed to contain an underground blowout and regain primary well control
CAUSE: WELLBORE PRESSURE EXCEEDS FRACTURE STRENGTH RESULTING IN LOSS OF CIRCULATION KI CK FLUID FLOWS UPWARD TO
PROGNOSED LOSS CIRCULATION EXCESSIVE MUD WEIGHT SHALLOW LOW PRESSURE ZONE
POSSIBLE WHEN SHUTTING IN FOR A KICK OR DURING KICK KILLING OPERATION SICP STOPS INCREASING AND/OR BEGINS TO DECREASE
KILL THE KICK ZONE BEFORE ATTEMPTING TO TREAT THE LOSS ZONE PREVENTIVE ACTION: MINIMIZE MUD WEIGHT MAINTAIN SUFFICIENT KICK TOLERANCE
Page 111
TERTIARY
WELL CONTROL
UGB
LOSS OF CIRCULATION OCCURS IN THE LOWER SECTION OF THE OPEN HOLE REDUCED HYDROSTATIC PRESSURE INDUCES A KICK
PROGNOSED LOSS CIRCULATION EXCESSIVE MUD WEIGHT LOW OR SUBNORMAL FORMATION PRESSURE
POSSIBLE WHEN SHUTIING IN FOR A KICK OR DURING KILL OPERATION
,._...,'!!"'~-"""!1
PARTIAL OR TOTAL LOSS OF RETURNS
MINIMIZE WELLBORE PRESSURE SURGES CASE-OFF POTENTIAL KICK ZONES BEFORE DRILLING INTO POTENTIAL LOSS ZONE
Page112
WELL CONTROL
UGB
Shut-in pressure build up begins to decrease Casing pressure fluctuations during shut-in stabilization period Shut-in casing pressure continues to increase while shut-in drill pipe pressure remains constant
TERTIARY
Total loss of circulation Electric wireline surveys can be used to determine if a down-flowing UGB is occurring Shut-in pressures are zero initially
Partial or total loss of circulation Shut-in pressures fall to zero psi
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, start filling the annulus with the present mud weight to control the kick "one 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 CONTROL
TERTIARY
UGB
GUIDELINES FOR UP-FLOWING UGB Kick zone pressure must be controlled before remedial action can be taken at the loss zone
HEAVY PILL • Determine the true measurement between the kick zone and loss zone (TV~.J • Determine or estimate the formation pressure of the kick zone (F~tcK) • Determine or estimate the formation pressure of the loss zone (F~055 ) • Calculate the kill mud weight required to kill the kick zone (KMW PPG)
KMWPPG
F~oss )} = (~KTVDK·Lx .052
+ SAFETY FACTORPPG
If KMWppc equals the density capacity of the weighting material, refer to the Heavy Pill /Gel Pill Guidelines. If KMWppc is greater than the density capacity of the weighting material, refer to the Barite Plug Guidelines • Build KMWppc volume equal to 2 to 3 times the open hole volume. If possible, remove the bit jets • Pump sea water at maximum rate, 3 to 4 times the open hole volume ahead of the heavy pill • Pump the heavy pill at maximum rate
HEAVY PILL I GEL PILL COMBINATION • Pump the heavy pill down the drill string at maximum rate while pumping the gel pill down the annulus to increase injection pressure at the loss zone • Adjust the annulus pump speed to place the gel pill at the loss zone as the heavy pill reaches the bit. Continue to pump the heavy pill at maximum rate
BARITE PLUG • A barite plug works best with gas blowouts. High flow rate salt water blowouts wash the barite into the loss zone. Bit plugging and/or stuck pipe may occur • Consult your Cementing and/or Mud Engineer for detailed recipes and application procedures
Page 114
WELL CONTROL
OBM
Gas that has dissolved into the base oil of oil base mud The pressure /temperature condition that will allow gas to break out of solution
/
•.
/< /•
...
OfTotal Expansion / ' • ,.:· ..... ,., .. /" /
,./ • • .!'· • • / . . . . . . ...; • • ,.:.. ,
No Expansion
Gas expansion allows kick detection well before the kick reaches surface
Solution gas does not expand until a near-surface bubble point pressure is reached
Gas solution in OBM does not hinder detection of large volume kicks (> 5 bbls), normal kick detection applies. After shutting in the well , normal kick killing
Page 115
~
. . . • . •
WELL CONTROL
n Do::D'\TIONS
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-dow n volume change
Kicks of 5 barrels or less can occur completely undetected under normal ope rating conditions
INFLUX GUIDEUNES If an influx Ia s uspected, stop the operation and circ ulate all o r part of bottoms up strokes through the c hoke 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, close the BOP a nd circulate the remaining strokes through the choke manifold
DRILLING Drilling operations have the greatest potential of circulating solution gas to surface
•
Adjust the high /low level mud monitoring alarms as sensitive as possible
• Stop drilling for mud wt adjustments, coordinate mud transfers with connections •
Use recommended procedures to circulate bottoms up after flow-checking a suspected drilling break and for all unaccountable pit gains
_DIPPING Tripping has the least potential of solution gas erupting at surface as solution gas will not migrate. Use recommended procedure to circulate bottoms up after all short or round trips
ltnlllllUN
GASAT IIJRFACE
If rapidly accelerating well flow oc curs, t he Driller must respond i mmediately
•
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
Pa ge 116
(C) CALCULATIONS
(A) WELL DATA Original Mud W eight
PP9 True Vertical Oepth (TVD) h
Kill Pump Pressure (KPP)
---,
Kill Mud Weight (KMW) KMW = (SIDPP
(E) DRILLPI PE PRESSURE SCHEDULE
""''l
Gn~ OKES
+ TVD + .0 52) + O rigin al Mud Weight +
KMW -
ICP = Kill Pump Pressure + SIDPP
-
( I)
(2)
""'
Kill Pump Rate (KPR)
.. "'..
apm
"D
-....
Surface to Bit Strokes
--
ICP =
.ill
• - -- - -
(8)
FCP = Kill Pump Pressyre x KM W + O M W
FCP ;
X
-
I I
( 5)
.,..
Fma l C•reulat•ng Pressure tFCP)
l
I
(4 )
1'4•
I•
0
+ 0 52) + - - -
lmtual C •reulaung Pressure (ICP)
PRESSURE
~
-'-
~
!=:
( 7)
;.
(")
)
.I IKI]
StkltO
(D) WAIT & WEI GHT PROCEDURE
Bit
~
-
FCP
1. Raise mud weight in pit to Kill Mud Weight value
2. Moni tor shut-tn pressures for gas migration. If necessary, bleed mud to maintain SIDPP at initial shut-in value.
(B) KICK DATA Shut-In Drillpipe Pressure (SIDPP) pol
Shut-In Casing Pressure (SICP) r--
pol
3. When kill preparations are complete, refer to Pump Start Up procedure and bring the well on choke. 4. Hold kHI pump rate (KPR) constant and adjust lhe choke to m atntain the Drillptpe Pressure Schedule until Kill Mud Wetght returns. 5. Stop the pump. close the choke and check shut-tn pressures. Sub Sea Stack - Clear gas from BOP and kill riser.
Pn Gatn
bbllj
6. Open the BOP and check for flow
INSTRUCTIONS 1 Record ICP, FCP and Stks to Bit In spaces tndicated.
2 Calculate strokes u>erease per Increment Stks to B•t ;. 10 Slks Inc Add Stks Inc to each oncrement unnl Stks to 81t •• reached
3 Calculate dfltlplpe pressure decrease per tncrement (ICP. FCP) ;. 10 = PSI Dec From ICP, subtract PSI Dec from each increme nt until FCP is reached.
0
<:
~
0
I""'
PUMP 81'4l'lllT..UP PROCEDUIUES
I I
CAPACIT IES (BBLS/FT)
I
0
L
J
[ -
'0
LENGTHS (FT) Ofillpipe
Heavyweight ~----
I
CAPACITIES (BBLS/FT)
-fl.-1 1+-
SURFACE STACKS
L
(1) Open the choke slightly while observing casing pressure
r---
(2) Just as casing pressure begins to decrease. start the kill pump
D rill Collars
(3) Adjust the choke to maintain casing pressure at shut-in value as pump speed is slowly increased to kill pump rate
c.:-~
....
DRILL STRING VOLUMe (BBL8)
<:: 111 1(1) Casing by Dr' I String
(1)
X
=
=
"U
tC
-
I I I I
X
=
I
(2)
X
X
=
~
(3)
X
X
=
I
(4)
X
X
=
I
~
Open Ho e by Drill Stnng
(2)
I I I I
I
I I I
-
I
I
X
I I
I I
X
I
I
X X
= = = =
I
I
I
Drill Sttl ng Vo l B.tt to
I
(4 ) When the pump reaches KPR , adjust the choke for the proper Drillpipe Pressure Schedule
(1) Open the choke slightly while observing the kill line pressure
=
Add colu.mn for Total Drill String Volume =
---
1
StkS to B it
+ IBBL..SISTKI
Surf~co
Annulus Vol
I
)
SUB SEA STACKS
Surfa.eo to Bit Strokes
r
L=-:J
=
.......
I
(3) Choke Line Volume (subsea only) I = X I Ackl column for Total Annulus Volume
~
+
I
Strokes :1:
BBLSIST K
Add column for
l
(2) Just as kill line pressure begins to decrease , start the kill pump (3) Adjust the choke to maintain k ill line pressure at shut-in value as pump speed is slowly increased to k ill pump rate (4 ) When the pump reaches KPR . adjust the choke for the proper Drillpipe Pressure Schedule
~
I"" I""
0
0
<:
~
g
CASING /CEMENTING
CEM API provides nine classes of cement to allow for various pressure /depth /temperature conditions Depth Range (ft) Class
0
0 - 6000 6000 - 10,000
E
10,000 - 14,000
F
10,000 - 16,000
A, B&C
G&H
0 - 8000
J
12,000 - 16,000
Cement classes are modified with accelerators or retarders to adapt to job requirement
0 A wide range of cement slurry densities can be obtained using various additives
Page 119
CASING /CEMENTING -
--------
-----
-
-
--------
IMPROPERLY DRILLED HOLE
Small hole 10, doglegs, washouts /breakouts, wellbore unstable, incorrect casing seal selection
POOR MUD CONDITION
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 circulating annulus pressure causes cement loss. Scratchers remove protective LCM
ABNORMAL PRESSURE
Complicates well planning /drilling. Heavy tubulars reduce clearances, high density slurries require more control , pipe movement more · liner
SUBNORMAL PRESSURE
Differential sticking, cement filtrate loss , low density slurries, reduced strength
WATER SENSITIVE
Sands with clay sensitive to fresh water filtrate, water block in dry gas zones
HIGH TEMPERATURE
Mud gelatin, flash sets cement without retarder, casing elongation /contraction problems, down hole tool limitations, cement strength retrogression
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. Formation conditions determine the pump pressure window Prevent cement /mud contamination Know wellbore formation fracture pressure limitations
Shoe pressure test
Tracer survey
Temperature survey
Production test
Cement bond log
Page 120
CASING / CEMENTING
RUBBER PLUGS {TOP & BOTTOM)
GUIDE SHOE
Page 121
CASING /CEMENTING
Ensure thread protectors are installed when handling casing Ensure casing is racked safely. Use adequate stripping for each casing layer to prevent bending /buckling. Rack casing with collars toward V-door Grades N-80 and higher should not be handled on metal racks and catwalks Place casing on the racks in the proper order of running in. Verify mixed weights and grades are in the proper running order. There must be no doubt as to the weight and grade of the casing. Unidentified joints should not be run Ideally, the casing should be cleaned, inspected, measured and drifted before the next layer is placed on the rack Remove thread protectors, clean the box and pin and protectors. Clean any debris from inside the casing . Reinstall clean pin and box protectors hand tight Any damaged joint and those that do not drift should be marked with red paint and laid aside Four persons are required to measure casing. One person on each end of the tape, another in the center to prevent tape sag and a fourth to visually check each call and record the measurement Measure, record and number all joints, crossovers and in-string components to permit ready identification Two or more of the heaviest weight joints should be held out to run at the top of the casing string to serve as a gauge ring and for wear purposes Measure several pin and threads of thread and coupled casing to determine the average thread length Casing should arrive on location already electronically inspected and pressure tested
CASING /CEMENTING
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 before running casing Measure the drill string while pulling out of the hole to obtain an accurate depth measurement Condition the mud as required . This generally consists of lowering gel strengths, plastic viscosity and yield point, removing drilled solids, lowering the fluid loss and improving wall cake properties If a hole problem is encountered on the trip out, the problem must be corrected before running casing . Reaming and mud conditioning until the hole stabilizes is the proper treatment Record drag /set down trends on the trip out to run casing. These values will be used to evaluate the drag /set down trends when the casing is on bottom and reciprocation begun 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 shoe. Consider the casing strap and space out accordingly At casing point TD, condition hole w ith GPM rates at least as high as the expected cementing pump rates
Page 123
CASING !CEMENTING
Install proper casing rams in the correct position in the BOP. Test the opening and closing of the BOP Verity rating of substructure and traveling equipment is adequate to handle casing and cement load Verity rating of substructure and traveling equipment is adequate to handle casing and cement load Ensure elevator bails are of the proper length for the job Ensure good condition of the drill line. Ensure proper number of block lines are strung to handle the casing hook load in air Visually inspect dead line anchor, hook, traveling and crown blocks. Magna flux or ultrasonic inspection should be considered for heavy hook loads Inspect breaking system on the drawworks Visually inspect derrick pins and bolts for wear. Plumb derrick if necessary Ensure mud pumps and centrifugal pumps are in proper working order Rig tongs should be checked for correct head size and new tong dies installed if necessary Visually inspect the slip bushing /bowl for proper operating condition Ensure stabbing board is available and in proper operating condition Ensure adequate size casing fill-up line w ith control valve is riggt!d up If 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 cleaned, tallied and drifted Casing joints numbered in order of running by thread type and weight Crossover subs checked . Damaged joints laid aside Calculate the casing strap for landing joint space out. Casing collar should be ten feet minimum distance from casing head flange. Ideally, cementing head should be 5- 15 feet 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 Guide /float shoe. float collar on location . Proper thread type and function tested Stage cementing or liner hanging equipment on location. Proper thread type and function tested Centralizers /scratchers on location. Type /size /number /spacing determined from electric logs /well plan Cementing plugs on location. Type /size and rupture pressure on bottom plug verified Casing head /slips /hanger /ring gasket /pack-off on location. Size /type /pressure rating verified. Flange bolts size /number checked Casing slips /elevators on location. Size /type verified Power /manual casing tongs on location. Heads /dies /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 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 notified for timing sequence of events (cementing and casing crews, inspection services, nipple-up services, test companies)
Page 125
CASING /CEMENTING
Clamp-on thread protectors are recommended when picking up casing Observe correct make-up procedures. Ensure torque gauge on tongs is accurate. Use API thread compound Ensure casing cementing head is properly dressed with top /bo«om 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. Communicate the proper running speed to the Driller. Running speeds of 0.75 - 1.5 fl/sec are typical With conventional float equipment, break circulation after running the first 2 - 3 joints to verify proper working order Apply thread lock compound to the pin ends of float equipment and shoe joints Pick-up /set-down weights for casing string should be recorded for each joint for early detection of sticking Bring casing string to a complete stop before setting slips. Do not allow elevators to get ahead of casing through tight spots Ensure proper stabbing procedures are used to minimize thread damage Fill casing every five joints minimum depending on casing size. Communicate fillup :;~;hedul"' 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 -- - - --- - - - - - - - - - - - -- - - - - - - - -- - - -----
-----------------
-
-
Determine maximum allowable cement 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 Design preflush /spacers to be displaced in turbulent flow. Contact time at the top of the pay zone should be a minimum of 10 minutes Use same mix water and cement in testing that will be used on location Check compatibility of cement slurry, drilling mud and spacers at room and bottom hole circulating temperatures Go to cement company bulk plant to check quality control on cement blending operations Batch mix all cement slurries if possible using ribbon or paddle type blenders. Do not use conventional jet type mixers for cement slurries On location, collect 1 gallon samples of dry cement and 2 gallon samples of mix water. Hold until out come of job is determined Calculate cement volume to be pumped and volume of mixing water required to mi.x cement Calculate time, volume and strokes to pressure equalization point after start of displacement Calculate time, volume and strokes to bump plug. Same calculations should be made for stage collar cementing Calculate 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
Page 127
CASING / CEMENTING
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 in the V-door if possible. All connections 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 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, 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. Stop reciprocation with casing near bottom if drag trends ind icate sticking tendency Batch mix the spacer and cement slurries if practical. Observe mixing operation, collect wet and dry samples. Weigh and record slurry continuously using a 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 rate on a continuous recorder for the entire job. Record total cement mixing and displacement time A typical cement job sequence of events: pump the spacer, release the bottom plug, pump the cement, 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 I indicators on cementing head to verify plugs did release. NEVER ALLOW THE CEMENT IN THE ANNULUS TO STOP 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 collar. Bump the plug with the proper pressure, 500- 1000 psi over circulating pressure or 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 more than the volume between the float collar and shoe
Page 128
CASING /CEMENTING
If float fails, shut in and apply approximate pressure the plug was bumped with. Hold pressure until initial cement strength is developed, monitor shut-in 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
woe
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 selling the slips to prevent buckling the landing joint Check mud pit and BOP for cement contamination, address immediately Ensure landing joint is compatible with slip and seal assembly, caliper casing OD A wellhead manufacture's representative should be present for slip, packoff and casing head installation. Test casing head prior to nippling up the BOP equipment If temperature survey is run to locate cement top, check with cementing company for the recommended WOC time before runn ing Clean casing head and flanges. Ring gasket and groove must be clean, dry and free of burrs or nicks. Do not grease the ring gasket All nuts and bolts should be clean and the correct size . All nuts should be tightened evenly for a proper seal Check all nipples, valves and lines on the wellhead and BOP stack for correct pressure rating and proper test procedures Cement drill-out practices should not jeopardize the integrity of the cement job Do not impose any forces on the casing that would alter the cement bond . Do not enter the casing until the desired cement strength is reached Calculate the top plug depth and communicate data to the Driller before drill-out Drill the plugs, float collar, cement and shoe with reduced weight and RPM to avoid shock loading the casing A formation equivalency or leak-off test in the new hole is necessary to determine the effectiveness of the cement seal and the formation fracture gradient
Page 129
CASING ! CEMENTING Monitoring cement jobs by continuously measuring pump rate, rate of returns, surface densities and pressures can provide early detection of some cementing problems
----'
....-, -~.-.~?Jt ' .. ~lr .• ~ '-.)" ~\!.;..~!; ' " CEMENT CHANNELING
UNSUSPECTED WELLBORE WASHOUT
-··
. . . . .
-,....,~-~·~·
• ~ ;", - t
•i
::. •
j
! '
-
.. .
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
LOST CIRCULATION
. .
Surface pressures are lower than anticipated Rate of flowline returns is lower than expected
. Free-fall inside casing is strong due to reduced annulus hydrostatic pressure. Might be indicated by strong vacuum at cementing head
INFLUX CONDITION
. Well comes out of free-fall later than anticipated . Surface pressures are tower 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
DOWN HOLE RESTRICTIONS
CEMENT SLURRY DEHYDRATION
. Surface pressures higher than expected . Rate of returns lower than anticipated during free-fall stages . Erratic rate of returns. First are higher than expected during deceleration, then level off before coming out of free-fall . Free-fall starts approximately when expected but ends pre-
.
maturely due to higher frictional pressures Surface pressures are higher than expected
. Rate of returns normal until dehydration starts then begins to decrease
Page 130
HORIZONTAL DRILLING HORIZONTAL WELL
A wellbore drilled parallel to the bedding planes of a roduction zone
LIMIT PRt::>DlJCTIONI OF UNWANTED FLUIDS
MAXIMIZE PRODUCTION
PENETRATE VERTICAL FRACTURES
INCREASE PRODUCTION
Page 131
HORIZONTAL DRILLING
Page 132
HORIZONTAL DRILLING
Page 133
HORIZONTAL DRILLING HCIIaON'fAL-.&.. PLAN FOCUS CONSIDERATIONS
PLANNING GEOLOGY
•
Formation type
•
• •
Rock strength /stress Porosity /permeability
• Formation dip angle
Mud type
•
•
Inhibition
• Hole cleaning
•
Mud weight
•
Drill string size
•
Down hole tool restrictions
• • •
Pump capacity
•
Washout/breakout
DRILLING FLUID "
HYDRAU LI CS
WELLBORE STABILITY
Formation pressure
Rheology
• Formation type
Over burden stress
•
Trajectory profile
• Lost circulation /Gas influx • Cuttings bed
Hole closure
HORIZICIC1'AL OPI!RA110NI FOCUS CONSIDERATIONS
OPERATIONS RIG
DRILL STRING
WELL CONTROL
WELL LOGGING
CASING
CEMENTING
•
Solids control equipment
• •
Drilling jars Inspection frequency
•
Kill calculations
• •
Top drive Pump capacity
•
Drill pipe size
•
•
BHAdesign Down hole motors
•
Torque /drag
•
BOP equipment
• • • • •
Kick detection MWD/ LWD
•
Casing design
•
Slotted liners
•
Predicted pick-up /slack-off weights
• •
Slurry design
• Centralizers
Mud condition
•
•
Contamination
Gas behavior Drill pipe conveyed /Coil tubing Pump down method
Page 134
Pipe movement
Gas will migrate to the high side of the wellbore and become trapped. To flush out the gas, AV must be increased to turbulent flow. When the gas enters the build-up section, slow the pump rate to normal
:t 0 :::0
i':i 0 <:
"0
"'.. Ill
-""''
i! ,... 0 :::0
;::: ,... ~
C')
-
HORIZONTAL.Ym_LL CONTROL KILL SHEET
-
Tru~
KMW • (SIOPP
KMW • l
I_
r
-•"' w
+ .052) ..
+
--~
ICP • KJII P ump Presaure
• Kill Pump Pressure •
FCP •
.~
Strokes to KOP
c
.tk.
(B) KICK DATA
...
Shut-In Casing Pressure (SICP)
~~l
--Pit Gain - 1
ICP
i.l
KCP
:131
--
KMW
"
Stka to ._.
KOP
PSI
+ OMW
ltn ItS)
+
19)
....
· {(_ -_ )x =-)-(
X
)
(D) WAIT & WEIGH T PROCEDURE 1. Raise mu(lweight in ph to Kill Mud Weight value bleed mud to maintain StOPP at initial shut-in value.
3 Refer to Pump Stan Up procedure, bring well on choke. 4. Hold KPR constanl and adjust the choke to maintain the Drillpipe Pressure Schedule unlit Kitl M ud Weight returns.
5. Stop the pump, close the choke and check shut-in pressures. Sub Sea Stack - Clear stack gas and kill riser. 6. Open the BOP an(! check for flow
r.
0 FCP
INSTRUCTIONS
0
:X: 0 ::0
N
Suc.a to ... 110) Bot
KCP • ICP + (
·-
5)
ile)
2 Monitor shut- in pressures for gas migration. If necessary,
Shut-,l n Onllpipe Pressure ( SIOPP)
r-
SIOPP
KOP C11culatmg »ressure (KCP)
Kill Pump Rate (KPR)
[
+
F tnel Ctrculetlng P,.aaure (FCP)
....
Surface to Bit Strokes
~
'14 )
~
....,
Q
:12)
""
---
+
ICP •
~
Kill ~p Pressure (KPP)
--
I -
STROKES PRESSURE
!1_11
KOP Measured Depth (KOP" 0 )
,
I
+ Orig.inal Mud Weight
lnttlel Ctrculauon Pressur• ( ICP)
KOP Vertical Depth (KOP""')
II
+ TVO + 052)
(E) DRILLPIPE PRESSURE SCHEDULE
Vertical Depth (IVD)
-
Cl
I
Kill Mud Weight (KMW)
Original Mud Weight
-
-
(C) C A LCULATIONS
(A) WELL DATA
1
Rec:.ord ICP. KCP, FCP, Stka to KOP and Slks to Bit in spacea lncllc.ated
2
Calculate Strokes I ncrement to KOP Stk s to KOP + 5 a S tk Inc
~
~ ,... 1:)
From 0 sUes. add Stkl to each Increment
~ ,...
u n til Stks to KOP le reaehed 3 Calculate Strokes Increment to BIL (Stks to Bit - Stks to KOP) + 5 • _ _ _Stk Inc
C')
From Stks to KOP, add thoe&e at.ks to e
•
(KCP • FCP) + 5
~
psi
From KCP. subtr&c-t the proaaure reduction from eac:h increment unul I=CP Is reached
~
Measured Depth
True Vertical Depth
[
CAPACITIES
tg
(BBLSJFT)
OP x Casing
Drill pipe
L J [ --=:J
L
c--
I
I I
I
DPxOH
Heavyweighl
~
r
Drill Collars
I
" --'
DC xOH
-
C
I
I
I
/ KOP
Select the approximate MIDDLE of the kick-off section
:X: 0
~
.. ..... J
I
'' t-;:-:-:-~... '
. ~
~
I
-]
~
N 0 <: ~ r-
.... ... "D
cc
w ....
0 I
I
I l4> I
I I
(2) (3)
X
X
I
I I
I I= I=
X Add Column fot Total Drill etring Volume
-=
I I I (2)
Add Column for Sttlng Volume to KOP
= ~
X X X
I I I
I=
r-
I I=
~
G)
I I I I
X X
X X
I I I I
I
=
I:
I=
I=
Choke Une Volume (&u.bs.ea only)
I
I
I I I
Open Hole by Drill String
I I I I (3)
I
~
X
I
X
I
I=
Add Co'umn for Total Annulu t Volume
Strokes to m iddle of KOP
Strlng Vol toKOP
I
I
I
bblslalk
I
~ lksto
KOP
INVESTIGATION PACKAGE
lftDII I
IW ELL '
ntDIII
>UMP #
I OD ~D"
ITIE
:II
~~01::
HOLE SIZE' MAX 0/DIII
I
.)aroaL >liMP t
PIIMP I 1 I <"D
PIIMP 1 OD
~-
= • :01
PUMP : 2
•UMP#
, OD
toP
- =--- -
~311
:01 !31 ~
!31 ~
:31 ~
:3d
=~
:Gil ~
,jill
:311 -1111 ~:Ill
!lid
:ml
=-:~ ~ iTYPe &CEPTH Of PROOLEII ;
P PG:
WT 1>0::1 n YU .lA I>•
L'
~
.6./n·
M D•
.6.STCSGOD'
SPN
l§B! o ATE:
nDIIIO::D
RIG'
II NITIAL
O:D
'"'·
lrM ' nmt! Of PROBlEM ; !... - ...
Page 138
t!!
~
.:.;..;...
[*
INVESTIGATION PACKAGE
•CIIT1IIGS 1Yl'E: CLAY fCl~ SH.II.E (114}. WIO flO~ GAAV!L fG\\~ LIIESTOIE flSI SAlT ISAI. talENT fCIIT), IMI89 (RU8l.IETAL fllj •CIIT1IIGS OESCRIPTIOii: ROtMl,fl.IT CIIT1IIGS (QJW~ IPliiTW CAVIHGS fC.IV,S~ BI.OCKY CAVIHGS fCAV,B~ ClAY lAW fCL8Lj.IMIII CLAY fiiSH)
Pa ge 139
fl811'HOLifmiCKJIIIEI REPORT DATE·
WELL:
REPORT#
~
RIG:
I!VENT DEPrH:
DATE:
LOCATION: TillE:
WELL DATA: (when event occurred) Csg Size:
Hole Size: #1 KOPMD: KOP Bottom #1 MD·
Shoe Test:
STRING DATA: OKelly
Shoe Anglo· _ _ _ Bit N:
MD: TVD: MD: TVD: Deg/100'• _ __ 112 KOP MD: KOP Bottom #2 MD:
MUD DATA: ( report ACTUAL mud propenles ) I'll:
...:
--
-..
O Rotatlng
O Mud Motor
OPERATIONAL DATA : (directly before event occurred)
11\/t' Auld Loss YP. _ _ Gets ___J___J_ _ pH· - -- OM/ Ratoo
Concentrahon
Inhibitor Type:
O Top Orivo
Type:
Size: BHA: C!Bultd C!Hold ODrop Last Trip M D: DC Size: Length: DC S ize· Length: Deg/100'·- - Jar Size: _ _ _ CHyd. OMeeh. Trip Setting.: UP Down. AngleCTD _ _ Jar PosittOn (from bit): O Tenalon C:X::ompre•slon Neutral Point Aec:eterator Position (from J&t) . HWOP Size· Length: DP ODIWt/Gr. !___) Ft DP ODIWt/Gr. I Ft: I
Types & Depths of Problem FO«nation(a) :
Mud Type:
EVINT tev!RITY:cnGHT HOLE IJinJCK Pill DRILLING REPORT t:
I!VINT CAUSE:
CEC
Rotaung WL Drag Trend: RPM·
Other.
Tor~uo
Shaker Evidence·
GPM:
t
Off/B Tq:
On/B Tq·
\'1108
Trend: Cir Press
INDICATIONS: Pipe Motion Prior To Event
O Rotating
O Up
O Oown
O Stalic
Pipe Motion After S tlcklng· CIDown Poaaible O Oown Restricted
O Oown lmpoa.alble
FREEING TECHNIOUE: OSucceu:ful OJna~JCXessful
0 0 0 0 O
Unconsolidated Form. Fractured/Faulted Form . Cement B locks Soli C ement Junk
DESCRIBE ACnON TAKEN:
!
' '
'
PRE\IENTTVE SUGGESnOH: (when event occurred)
DRILLER:
TOOLPUSHER.
D we:LL80RE GEOM ETRY
SUSPECTED CAUSE(S):
0 Settled Cuttings Pipe Rotation After Sticking: 0 Rot Pouible 0 Rot. Restricted 0 Rot tmpoulble 0 Reactive Shale C ir, Pressure After Sticking CJProas. Nonnal O Pre.s.s. Res-tricted 0 C t . lm polliblo 0 Gao-Pressured Shale D Hydro-Pressured Shale SPM· C irculating Preuure: 0 0/Burden Stress WiUTheJarTrip?O YM O No II "No", why nol: 0 Tectonic Stress Other. I I
0 DtFFERE NTIA~ STICKING
COMPANY REP:
::::! ~
STICKING MECHANISM: Q HOLE: PACK .OFFJ9RtDOE
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0
P ress Trend:
Other-
Operation When Event Occurred.
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Sf() 11\/t'
PIU IM
0 0 0 0 0
Stiff Assembly Key Seat Micro Doglegs Ledges U/Gauge hole
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0
£ (j)
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I
WELL:
LOST CIRCUlA110N
IREPORT DATE:
LOSS SEVERITY: OSEEPAGE D PARTIAL DTOTAL
LOCATION:
RIG: LOSS DEPTH:
DATE:
Csg Size:
MD:
Hole Size:
MD:
nME:
CAUSE OF LOSS:
Shoe Test
WEL.L DATA: (when event occurred) TVD: TVD:
REPORT # MUD REPORT t:
STRING DATA: O Kelly O Top O(ive O RotatJng O Mud Motor Hole Size: - - DC Si:e; Length: DC Size: Lel\gth:
S hoeAng~:
Last Trip M D:
Stal:>ilizer Positions: DP ODMit. ___)_ _ Ft:
Types & Depths of Loss Zone(s)!
HWDP SiZe:
Length:
DP ODM/t: _ _I _ _ Ft:
Other:
MUD DATA: (report ACTUAL m u d properttes) Fluid Loss: PV: _ _ YP: _ _ Gets: _ _/_ __/_ _ pH: - - - 0/W Ratio: System L C M ; _ _Lbslbbl Polymer Type~
....-o ...
CQ
•...
Operation;
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Depth Loss Started:
GPM: Cir Press: CEC. Slip-To-Slip Pipe Speed: _ _ _ LbslbbL _ _ Gel: _ _Lb&ibbt Other:
Concentratjon:
Inhibitor Type :
i
OPERATIONAL DATA: (when event oaurred)
Wt:
M ud Type:
Fl/Se
ECD@ Lou Zone. M ax Csg Press Before Loss:
:::r G) )).
Other.
:j
CLASSIFICATIONS OF LOSS. D PRESSURE INDUCED FRACTURES D NATURALLY EXISTING FRACTURES/PERMEABILITY OTHER: CAUSE(S): D Welt Control Oper. DGes Migration O Excessive Mud Wt 0 Excessive Cuttings Load ClHigh EC.O D High Surge Pressure D lmposed Pump Pressure Other: O Oepleted Zone O Unconsolidate
MUD LOSS DATA: SEEPAGE • < 20 SblsJHr PartlaJ = > 20 BblsJHr BblsJHr: _ _ _@ _ _ _ GPM Static Loss: _ _ _Bbls/Hr
Total= No Rotum.s
Depth: Depth:
Depth: Depth:
Sbls/H r, _ _ _@
GPM Statie Loss: _ _ _Bbl.s/Hr GPM Static Loss; Bbls/Hr
Sbls/Hr: Bbls./Hr, @ G PM Static Loss: Sbi&IH' @ SPOTTING RESULTS: 0 Successful O Partialty Successful o unsuccessful Vol: Gel Content: Lb&/Bbl Pill# 1: O WBM O OSM Wt' MD _ _ _TVO Wait Time: _ _ _ Bbls Spoued: Depth: Pill Type: O LCM O Cement o:;onk[JSpeciatty Pill Other. n FineO Med O Cor Lbs/Bbl: _ _ _ SQUEEZE RESULTS: O Successful 0 Partially Suecessful 0 u n succes.sful M aterial: IIFfne O Med O Cor Lbs/Bbl: _ _ _ Bbls Squeezed: _ _ Depth: MD TVD Press Held: _ _ _ M aterial:
- --
O Fine O Med O Cor lbs/Bbt:
Material:
Pill# 2: D WBM D OBM
Wt:
Vol;
Gel Content: _ _ _Lbs/Sbl
W&it Time:
Notes;
SPOTTING RESULTS: 0 Successful CJ PartiaUy Successfvl O Unsu ccessful Bbls Spone
Pill Type:D LCM D Cement OOunk CSp ecia1ty Pill Other: O Fine O M ed O Cor Lb s/Bbl: _ _ _ SQUEEZE RESULTS: O Successful M aterial: M aterial: O F;ne O M ed O Cor Lbs/Bbt: _ _ _ Bbls Squeezed: _ _ Depth: M aterial:
TOOLPUSHER:
O Fin e O M ed O Cor lb&IBbl.
MUD ENG:
waitnme:
- --
0 Partially Successful 0 U n successful MD TVD Press Held : _ __
No-tes:
COMPANY REP:
0
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11'1
DIMENSIONS I PROPERnES I REPORTS: l ength : 00; 10:
VVVFt:
Grade; - - -
Conn Size 1 Type:
Stres.s ReHef: yes no Bore Restrictions:
H SJC0 R&&ista nt : yes no Oil 2 2
Resistant
Inspection Report: yes no
yes n o Temp Limit: _ _ Batl l tfe : - -
. "'....
.,•
0 Inspection Report
O Supply Co Paper \Nork
O Fishing Dimensions Sheet
O Operat'ons M anual
0
Settfng Calibrations Sheet
MATCH SERIAUMODEL #ON TOOL W ITH ALL PAPER WORK
0
Settings & Ca.librations:
O the-r:
-o
PAPER WORK: LOCATE: 0 Ca rgo Manifest
CORRECT TOOL
0 INCORRECT TOOL
:j
Commen ts:
OPERATIONS: C H ECK: O D amaged Container O Exptosive/CO«osives M atked
Special Handling I Operations I M aintenance:
Safety R&eommendations: - - -- - - - - - - - - - - - - - - - - - Make-Up T q: FVLbs Thread Compound: - - - - - - - - - - - 0 /Pull Limit: Tq Limit Pump P ress Limi t - - - - - GPM M in~ _ _ _ Max : _ _ _ Hydro Press Limit: - - - -M ex Rota ting Hrs:
Angle limit: - -
Other.
D Battery pack
O Hazardous Material Secured 0 Pres sured Vessets Seeured Other.: - - - - IN SPECT TOOL FOR: 0 Thread Protectors 0 Thread Damage O lmpact damage
~
0 Bent I M ashed Tube 0 Water Damage
Other. - - - - - -- - - -- -
VERIFY WITH MANIFES ~ Q Back-Up Tool O Spare Part(s)
0 H andling Tool(&)
'Other. ==~==~~====---================ 0 Operati"g Tools
O Cros.sovers
Other. - - -- - - - - - - - - - - -
INSPECT: O Tool Bore O Aocess Ports O Safety Clamps
Tools included w/shipment: yes no Available In Area: - -- - - - - - - - - - -
Fishing Records Available: yes no SUPPLY COMPANY RAnNG: R ep. Helpfulness: 1 2 3 4 5 6
5 6
Fi-shing Dimension
Sheet Shipped: yes no
FUNCTION TE Sl': O Vatves
0
Fl~ppers
Rep. A vailability: ·1 2 3 4 5 6+ ' Tool Arrival Condition· 1 2 3 4 5 e
Knowledge Of Tool: 1 2 3 4 5 6 Spare Parts Condttion: 1 2 3 4 5 6 123456
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::!
OPERATIONS:
Ft&hing Tools R.equlred: - - -- -- - - - - - - - - - - - - - - - - -
~
(I)
0 Tool Conn Size/Type
Other· - -- - - -- - - - - - - Tool Operating Condition: 1 2 3 4 5 G Tool Operator Knowtedge: 1 2 3 4 s 6
0
~
0
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WELL DATA: (when failure occurred)
S TRING DATA: 0 Kelty
Csg Size:
MD:
TVD:
Hole Size:
M D:
TVO:
To: Hole Wa.shollt %: _ _ _ MD From: Dogleg MD From:
Length: - - - - DC Size: - - - - Length: - - - - DC Size· Jar Position (from bit): Accelerator Position (from j ar)· - - - - - - -
To: - - - - -
Si~e ·
Neutral Point: (from b it)
BHA O Build 0 Hold 0 Drop
HWOP Size.
OP ODMitJGr - - -'- - - ' - - - FL Other.
Length : - - - - - -
D P 00/Wt.JGr ___1___1 _ FL
Rot_a t_in g VVt: - - - - - - - P/U WI: - - - - - - - - - - - S/0 WI. -
----
Sack-Up Tool: O On·Site O Avaflable Spare Parts : CJ On-S1te () Available
Oehvery rime: - - - - - - - - - - -
Delivery T!rne: - - - - - - - - - - -
Oown-Time H ours: _ _ _ Supply Co Respon se Ra t •ng : 1 2 3 4 5 6 O Not Apphcable
Drag Trend· - - - - - - - - - - - - - - - - - - - - - - - - - Other. _ _ _ _ _ _ _ _ _ _ _ _ __ _ _ _ _ _ __ _ _ _ _ _ _ _ ___ RPM: ____ 01!/B Tq: WOB: - - - - - - -On/B Tq· - - - - -
1- - - - - -- - - - - - - - - - -- - - - - - - - - - - - -
Torque Trend: GPM:
C 1r Press:
Pre-ss Trend :
Failed Tool: - - - - - - - - - - - - - - - - - - - - - - - Failed P~ut: - - - - - - - - - - - - - - - - - - -- - - -- - - - - - -
OescribeFailure: __________________________________________________________________
Cause(s): ____________________________________________________________________________________________________________
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TOOLPUSHER:
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FAILURE DESCRIPTION:
'llfM!JI7M
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RECOVERY:
OPERATIONAL DATA: (when event occurred)
..e
O Mud Motor O Shock Sub
Angle@ TO. - - - Deg/100': - - - -
Opemt~n= -------------------------
"'..
0 Rotatmg
Bit it. - - - Type:
omec _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ __ _ _ _ __ __
.,..
O Top Dnve
Shoe A ngle : _ __
rJCIMI:
~REP:
TOOL OPERATOR:
~
C)
Ill
I
WEU:
RIG:
DRILL STRING FAILURE REPORT FORM
LOCATION:
FAILURE LOCATION: 0 DP IJHWDP DOC
REPORT#
FAILURE SEVERITY:OPARTED OTWIST-OFF DCRACKED DWASHOUT
TDMD:
FAILURE DATE:
W ELL DA TA : (when failu re occurred) Csg Size: Hole Size.:
IREPORT DATE:
STRIN G DATA: 0 Kelly
TIME:
DRILLING REPORT t: 0 Rotating
O TopOrlve
TVD:
Shoe Angle:
Bit # : - - - Type;
MD:
TVD:
Aogle@TO:
DC OD/ID : _. - ' - - U>s/Ft: _ _ Conn Type:
To:
Deg/100': Deg/100':
DC 0~--'-- U>s/FI: _ _ Conn Type: Lenglh: Jar P ' ton (frotn bit): Accelerator Position (from j ar):
# 1 KOP/Dogleg MD From:
To:
#2 KOP/Dogleg MO From:
Hole Washout%: _ _ _
To:
M D From;
Size:
0 M ud M OtOf O Shoc.k Sub
MD;
BHA: O Build 0 Hold 0 Drop Length:
N eut a l P oin t: - - - H WOP Size: _ _ Conn Type:
Other:
DP OD/Wt/Gr. __}__/_ _ Ft:
~
Length:
DP OD/Wt/Gr. __/_ _/ _ Ft: - - -
Mud Type:
l
~
t
Ro ta ting vvt:
PIU IM:
O Smooth O Erratic OH/8 Tq:
WOB:
O n/B Tq:
0 Smooth 0 Erratic
TOtqu e Trend:
M udWe+ght:
Sand:
%
Lbs./Bbl! _ _ _ Corr. Ra te BIHC>Ie Temp; _ _ _ CO PPM; Lbs./Bbl:
pH : _ _ Corr. lnhtbitor Type:
SIOIM:
Dreg Trend: RPM:
:::!
M UD DATA: (record A C TUAL mud p roperties)
OPERATIONAL DATA : (when failure occurred)
Operation:
Oxy PPM; - - - H S PPM : Seavenger Type: Other,
FAILURE DESCRIPTION: O OP Tube FCltigue
0 Combination Tenston/Torsion
D BHA Conn Fatigue
O Collapse
D Burst
O Connection Leak 0 \Neld Failure
0 Sulfide Stress Crack
O Spl ~
Box
O Tension
O Torsioo
0 Mechanical Failure Of String Equipment (Jar, MfMotor. Etc.):
Othttr: OP Tube Failure: _ _ Inches From 0 Bo:x O Pln Shoulder BHA Conn Failure" _
_
serial II:
Last Insp. D ate!
Ft From Bit 0 Comp 0 Tension Serial #s Of Jcints: PinN:
Conn Leak: O OP O HWDP D OC
Serial #$ Of Joints.: Pin#
Bo>d#
Box#
Insp. Repott # : La.st Insp. Oate{s):
TOOLPUSHER:
Rotating Hrs: _ _ _ RotatJng Hrs: _ _ _ R otating Hrs:
t..ast Insp. Oa te(s) :
PREVEN TIVE SUGGESTION S:
DRILLLER (on tour):
~
a <:
~
GPM: Cir Press: Press Trend: 0/PuULimit: Set Down Limit TqLimn: Wt lnd Reading @ Failure: T q @ Failure: Pre.s.s @ Failure: TYPE O F FAILURE;
~
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Ot.her:
COMPANY REP:
~ C)
l'l1
•
~DII LOCATION:
-.:
iGCKDATE:
Cs.g Size:
MD;
HoloSiz.e_
M O·
Kick TOlerance· _ __
Fonn. Press @ TO·
1C11J. liiW:.
Shoe Test: Shoe A ngle . _ _ _
TVO
REPORT#
_:jREPORT DATE:
we .. ,"[J. 'ii1.01......0 . .411MIIIICiill: ClnduniiiCiilf rua •a • • ~~: ' · • . · .. DRILLING ltEPORflc
.
ORIG.IIW:
WELL DATA: (when event occuHed)
....
l ..
WELL:
TVO. Angle@ TO - - Shallowe&1 Abnormal FP (>9.0 PPGE): TVO Other
STRING DATA: O Kelly Q Top Drive DC 00110 .
H~6-
I
Q Rotatlng
OUI
O Mud Motor O DS Floet Velvo
DC 00110. _ _ _/_ _ Ft:
Ft · Lbs/Ft. - --
Ft OP 00/Wt - - - ' - - Ft @SPM. _ _ Presaure loss.
0 OOMII. - - - ' - - Ft. SS Choke Ltne ro . _ _ Ft Otner
I ::!~
OPERATIONAL DATA: (When event occum!d)
..
"V
"'•
~
·Tnpln
Coring = logg'ng WCementtnt O.her M ud Type: :::WSM O OSMIS8M 111/t I n - - - 1Ait Out~ --- Slip-.To-Sbp Trip Speed Out. _ _ _Mtn In Kick W arning Signs: ....~ Onthng Break O VV.U F·tow O P ftGain C Cir Preaaure Loss 0 Incorrect Hole Fill Volume Other Operation: 0 O""
Cause Of Kick: O Drilled Hi'Qh Prell Zone O light Mud Wt Pumped 0 Total LOll Or Cir
O Cut M ud Wt (water.oil, gas)
~
M 1n Other.
0 Total loa& Of Cir
O Gas@ Sea Surface
CJ Improper Hole Fdl P rocedure
O Swabblng
::!
0
~
Other:
S HUT-IN DATA :
Tlmo O f Kic k:
Shut..fn Procedure: t 15oft
1Herd CJFast
~Kick Type: O Under Salanoo Kick
Drill String: CJ On Bottom BOP Clostng Pressure:
(Ji nduced Kick
0 O ff Bottom Bit M O;
SIOPP·
~
D OutOf Hole
SICP·
Prt Gain
Kick Fluid Ty~ : O Wator C1011 l)Gaa O Unk nown TVO Of K ick :
Gas M igration Observed: Cyes O no
Other::
KILl. OPERATION DATA: Kill Procedure: KiU MW· String
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- --
Mo~ment
p,....KIII Operation:
wait & we.ghl Me1.hod
K .. Pump Rate - - SPM During Kin:
None
o snubln
0 Circulation Method
~
S tnp In
0 Heavy Mud Cap
Other
O BuJihead
Other.
O VOiumotnc M e thod
S&fety Fact<>< (~ any), Added MW - - -
Added Back Press·
Other
Hung-Off 0 Rocate 0 Rec«proc.ate
8nefly Describe Kill Operatoon
DRILLLER (on tour):
TOOLPUSHER: -----
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COMPANY REP: - -
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