Reliability of DownholeEquipment
A One Day Course on Understanding WellEquipment and Workover Failures and
A One Day Course on Understanding WellEquipment and Workover Failures andImproving Well Production Reliability.
George E. KingFebruary 2010
Safety MomentDon’t park within the rig guy wires.
Time Between FailuresReferring to the figure,the MTBF is the sum ofthe operational periodsdivided by the numberof observed failures.
Wikipedia
Misleading Numbers? Does it mean thatthe component will last 50+ years?
What is the Definition of MTTF and MTBF?
Mean time between failures
• Mean time between failures (MTBF) is the predicted elapsed timebetween inherent failures of a system during operation. MTBF can becalculated as the arithmetic mean or average time between failures of asystem.
• Mean time to failure (MTTF) measures average time between failureswith the modeling assumption that the failed system is not repaired.
1. Definition of MTBF depends on definition of what is considered a systemfailure. For complex, repairable systems, failures are considered to bethose out of design conditions that place the system out of service andinto a state for repair.
2. Failures that are left or maintained in an unrepaired condition, and donot place the system out of service, are not considered failures underthis definition. Malfunctions?
Wikipedia
Mean, Median and MTTFMean time to failure or MTTF, (a mean life function) is widelyused as the measurement of a product's reliability/performance.Calculated by dividing total unit(s) operating time by total numberof failures. Valid only when data is exponentially distributed; apoor assumption that implies failure rate is constant.
The mean or average is the mathematical average of the data in aset. A set of numbers of 1, 2, 3, 4, 100, would have a mean of1+2+3+4+100 = 110/5 = 22
The median is the value that splits the data is half. For the 1, 2, 3,4, 100 data set, the median is 3.
Should Reliability be Expressed as a Function ofTime or Cycles at Specific Conditions?
• Associated with time, the mean time to failurebecomes a measure of reliability, e.g. :– for cyclic equipment; the reliability at 50,000
cycles should be > 50%.
for gauges, the reliability at 200oF should be 90%.– for gauges, the reliability at 200oF should be 90%.
• Reliability of a product should be specified asa percentage value with an associated time.Ideally, a confidence level should also beassociated, which allows for consideration ofvariability of data being compared to thespecification.
Common MTBF Misconceptions
A battery may have a useful life of 4 hours anda MTBF of 100,000 hrs!
What this really indicates is that for a
Wikipedia
What this really indicates is that for apopulation of 100,000 batteries, there will beapproximately one battery failure every hourduring a single battery’s four-hour life span.
Failure Data BasesExamples…
String Item
ServiceTime,
years**No. of
FailuresMTTF,years*
Blast Joint 414 0 414
Downhole Packer/Hgr 837 7 119
Expansion Joint 3198 1 3198
Fow coupling 34794 0 34795
Gravel Pack Packer 1089 3 363
Gravel Pack Screen 1561 2 780
Landing Nipple 17324 1 17324
Millout Extension 6099 0 6099
Nipple for WR-ScSSV 4372 4 1093
Perm. Gauge Mandrel 1113 111 10
Prepacked Screen 1020 1 1020
The best way to use theMTTF is as a trend. Veryhigh numbers indicatethe part is very reliable.
Prepacked Screen 1020 1 1020
Production Packer 10268 17 604
Pup Joint 72078 4 18019
Screen 800 8 100Seal Assembly -Conventional 3101 13 238
Shear Out Safety Joint 584 0 584
Sliding Sleeve 2181 2 1090
Tubing 50485 76 664
Tubing Anchor 6569 2 3284
Tubing Hanger 8818 15 588
X-Over 16711 1 16710
Very Early and Incomplete Datafrom Sintef – 1995
the part is very reliable.
** Service times of lessthan about 250 years maynot be sufficientlypopulated to yield validnumbers.
Failures – Over Time
Your Warranty Period
Hazard AssessmentRisk = frequency xconsequence
Semi Quantitative Assessments
Technical Risk Identification andManagement
• Most risk analysis are focused on safety. Thispresentation focuses on managing technical riskduring wellwork.
– Technical risk management starts after the safetyassessment is complete, understood and approved.assessment is complete, understood and approved.
– Technical risk uses success and failure histories – both inthe company and in the asset.
– Understanding the well flowing system is the single,biggest goal of the operations in Petroleum engineering.
Technical Risk – Logic Sequence
• Action – each action involves sequences of possibilities – bothgood and bad.
• Potential outcomes – identify events that may occur duringexecution of the operation.
• Signposts - By study of analogous cases, identify the earlywarning signs that predict failures.Signposts - By study of analogous cases, identify the earlywarning signs that predict failures.
• Probability– assess likelihood of occurrence of unscheduledevents.
• Contingency plans – remedial action to recover from nonscheduled events.
• Construct a learnings loop, with a a single point of accountabilityand make it work.
Adapted from SPE 52968
Managing Technical Risk Decision Tree:Outcomes and Probabilities
Actions
OutcomesProbabilities
Reactions
This becomesextraordinarycomplex veryquickly.
Actions
SPE 52968
Technical Risk Ranking
• High – could result in losing the well orrequiring extensive rig work to repair.
• Medium – will significantly extend the work orsharply increase the complexity.sharply increase the complexity.
• Low – events requiring a management ofchange process decision, but not endangeringthe well.
Inspections – Do they help?
• Are the right items inspected?
– What creates a failure – in this part or another?
• When is it inspected?
• Does the inspection stop failures?• Does the inspection stop failures?
• What is done about out-of-spec parts?
– Rebuilt, recyled or just resold?
• What changes as a result of inspection?
RBI and Materials Operating Envelopes (MOE’s)
• Risk-Based Inspection (RBI) help focus resources &increase reliability.
• RBI studies rely on assumptions of past and futureoperating conditions.
• RBI focuses much more heavily on inspection activities
21
• RBI focuses much more heavily on inspection activitiesthan controlling operations & monitoring activities.
• Knowledge / control of unit’s operating envelope helps RBIplan.
• Materials operating envelope (MOE) studies, althoughcomplements RBI. Creating a MOE typically easier &more efficient in conjunction with RBI.
Buchheim, et.al., Equity Eng. Grp, 2006
Materials Operating Envelopes (MOE’s) DefineLimits
• MOE defines limits for each part of operatingparameters in a “unit” (pH, flow rate, temps,chemical or water inj. rates, acceptable levelsof corrosive constituents, etc.).
22
of corrosive constituents, etc.).
• If limits are not exceeded, degradationshould be predictable and reasonably low.
• If limits are exceeded, excessive equipmentdegradation due to corrosion could occur.
Buchheim, et.al., Equity Eng. Grp, 2006
Assessing Potential and Specific DamageMechanisms
• Material (general and specific information including heattreatment, chemistry, strength level, etc.)
• Service exposure (general and specific), normal andupset (trace amounts of corrosives, concentration,cycles, & particularly human factors.)
• How often and how quickly does damage occur?
23
• How often and how quickly does damage occur?• Mitigating factors (coking, crack closure, residual
stresses, coatings, chemical additives, water wash)• Any monitoring data or other warning systems (probes)• Previous inspections and effectiveness at targeting
particular mechanisms• Morphology of the damage
Buchheim, et.al., Equity Eng. Grp, 2006
In-Service Damage Types
• General Corrosion
• Localized Corrosion
• Pitting, Crevice, and Grooving Corrosion
• Planar Cracks
24
• Planar Cracks
• Branched Cracks
• Metallurgical Changes & Hydrogen Effects
• Distortion
Buchheim, et.al., Equity Eng. Grp, 2006
In-Service Damage TypesGeneral Corrosion
• High Temp Corrosion and H2/H2S Corrosion
• Moderate Velocity Sour Water
25
• Oxidation
• Atmospheric Corrosion
• Some Hydrofluoric Acid (HF) Corrosion
Buchheim, et.al., Equity Eng. Grp, 2006
In-Service Damage TypesLocalized Corrosion
• Low or High Velocity Sour Water
• Dilute Acid Corrosion
• Galvanic Corrosion
26
• Galvanic Corrosion
• Corrosion Under Insulation (CUI)
• Erosion/Corrosion
• Injection Point and Dead-leg Corrosion
Buchheim, et.al., Equity Eng. Grp, 2006
In-Service Damage TypesPitting, Crevice, and Grooving Corrosion
• Under deposit corrosion (scale, microbe,wax)
• Weld area attack
Water handling
27
• Water handling
• Amine salts
• Stainless steel attach from chlorides
Buchheim, et.al., Equity Eng. Grp, 2006
In-Service Damage TypesDistortion
• Bulging
• Blistering (H2)
28
• Creep
Buchheim, et.al., Equity Eng. Grp, 2006
Monitoring Methods
• Corrosion probes
• Hydrogen probes
• Coupons and physical probes
29
Coupons and physical probes
• Various measurements and scanning
• Stream samples
• Process variable monitoring
Buchheim, et.al., Equity Eng. Grp, 2006
Mitigation Methods
• Physically modify the process– Change temperature and/or velocity– Removal of stream fractions
• Chemically modify the process– Water washing
Injection of chemicals to change pH or tie up constituents
30
– Injection of chemicals to change pH or tie up constituentsor to form a film barrier
• Isolate the environment from the material– Organic coatings and thermal spray coatings– Metallic linings– Weld overlay
• Upgrade the materials
Buchheim, et.al., Equity Eng. Grp, 2006
Sources of Outcome, Probability, andContingencies
1. Review:• Standard industry operation prediction vs. asset
experience. Pick best-in-class operators andstudy their approach.
• How do best practices reduce problems.• How do best practices reduce problems.
2. Historical data bases.
3. Probability distribution function. Careful –lumping data together can be misleadingunless you understand individual conditions.
Adapted from SPE 52968
Where to begin?
• Historical performance – what has worked and whathas not?
• Are the metrics correct? Do they help or mislead?
• What early warning “flags” were evident in post• What early warning “flags” were evident in postappraisals of failures?
• What best (and worst) practices were observed?
Let’s Start
• First: Workover/Intervention evaluation providesthe most clues about failures.
– What is broken
– Why– Why
– What can be repaired
– What can be prevented
• Second: Production operations provides the mostclues about best practices. However, we seldomstudy things when they are working correctly.
Scorpion Plot• A scorpion plot is a plot by rate of production change
vs. economic return for workover/intervention jobs .
Cu
mu
lati
ve
Exp
en
datu
re
Uneconomic
Cumulative Productivity Gain
Cu
mu
lati
ve
Exp
en
datu
re
HighlyEconomic
ModeratelyEconomic
BorderlineEconomic
SPE 30649
Look at the type of job in each section of a
field-specific scorpion plot.
Highly Economic
11%
8%
22%
41%
7%8%
Acid Jobs
Cleanout
Cleanout & Stimulation
Conversion of GL to ESP
ESP Replacement
Integrity Repair
Moderately Economic
9%6%
11%
6%23%
16% Acid Jobs
Cleanout
Cleanout & Stimulation
Conversion of GL to ESP
ESP Replacement
Integrity Repair
Others
Lift Optimization
3%
41%Others
Borderline Economic0%
4%
8%
0%
17%
31%
40%
Acid Jobs
Cleanout
Cleanout & Stimulation
Conversion of GL to ESP
ESP Replacement
Integrity Repair
Others
29%Others
Uneconomic
11%
11%
7%
7%0%0%0%
4%4%
19%
4%
4%
29%
Acid Jobs
Cleanout
Cleanout & Stimulation
Conversion of GL to ESP
ESP Replacement
Integrity Repair
Others
Conversion of BL to ESP
Convesion of ESP to GL
Conversion to Water Inj.
ESP Installation
Recompletion
Water Shut-Off
SPE 88025
!
The number of jobs performed may holdsome clues to success.
Highly Economic (# jobs, % of total)
23, 11%
16, 8%
45, 22%
85, 41%
15, 7%
17, 8%Acid Jobs
Cleanout
Cleanout & Stimulation
Conversion of GL to ESP
ESP Replacement
Integrity Repair
The more the field doesa job, the better theyget at it if learnings areincorporated as the jobsprogress – for example,lift optimization.
6, 3%
85, 41%Integrity Repair
Others
Uneconomic
3, 11%
3, 11%
2, 7%
2, 7%
1, 4%
1, 4%5, 19%
1, 4%
1, 4%
8, 29%
Acid Jobs
Cleanout
Cleanout & Stimulation
Conversion of GL to ESP
Conversion of BL to ESP
Convesion of ESP to GL
Conversion to Water Inj.
ESP Installation
Recompletion
Water Shut-Off
lift optimization.
Some jobs, like watercontrol, remain verylow success ratebecause the symptomis treated, instead ofthe problem.
Some jobs have a high amount of risk -Fishing Limits
• Continued fishing past some economic limit is failure,even if the fish is retrieved and that portion of thehole is saved. (SPE 9102)
• Changes of recovering a fish decrease sharply withtime.time.
• Cost of the fishing operations (per day) must bematched against the sunk cost of the well.– Time and cost for a single round trip – historical time
– Knowledge about the fish and how to retrieve – BestPractice is drawings of BHA’s, photographs, camera work,etc.
What can be done to improve knowledge?
Approximate Drilling Fishing Success vs. Time
Successful Fishing
6
7
Why does success decrease with time? What jobs are highly impossible? Who makes thedecisions? When do you quit?
0
1
2
3
4
5
6
0 100 200 300 400 500 600
Time (hrs)
Fre
qu
en
cy
SPE 9102
Cased hole fishing success with time.
This is a compilation of several jobs,but it indicates that cased holefishing is usually quickly successful.
If the fish is not quickly recovered,there are usually severe wellborethere are usually severe wellborecomplications that will prevent fishrecovery. What are they?
Fishing Time in Days
Going beyond equipment - Formation perm is NOTconstant – Effect of Declining Reservoir Press.
What are the consequences of reduced permeability – can it be avoided?
Dominance of Large Pores on Permeability – If thelarge pores are damaged, productivity drops!
20 m
Large pores and naturalfractures dominatepermeability.
20 m Not every instance is alike –pore throats, wetting layers,condensate phases, clays,minerals and fines influence theactual perm.
How can this potential problem be avoided? What has to change in the completion &workover approaches?
Risk of a Blowout – general data from 1960to 1996 – SPE 39354
Area Blowouts Number ofwells drilled
Blowouts per100 wells
The outcomes, probability and even the warning signs are obtainable from casestudies.
Thought and investigation are needed to understand the data.
wells drilled 100 wells
Louisiana 123 29,000 0.42
Mississippi 20 11,000 0.18
OCS 245 180,000 0.14
Texas 450 310,000 0.15
Totals 832 380,000 0.16
Although average numbers present one view, numbers for a specific area (Louisiana)indicate the risk may be higher in that area. Why?
Blowouts vs. Type of Operations During Completions
Operation BO Activity BO
Installing equip. 25 Nipple down BOP 5
WOC 5
Casing running 3
Cementing casing 2
Fishing 1
Stuck pipe 1
LOT 1LOT 1
Set well plugs 1
Well Tests 10 WOC 5
Cementing Casing 2
Tripping In 1
Tripping out 1
Squeeze cementing 1
Circulation 5 Killing 2
Perforating 1
Cleaning the well 1
Gas Lifting 1
SPE 39354
Blowouts vs. Type of Operations During Workover
Operation BO Activity BO
Pulling Well Equipment 37 Pull Tubing 15
Stuck Pipe 4
Pull/Drill plugs 3
Pull WL 2
Logging 2
Perforating 1
Cleaning well 1
Snubbing out 1Snubbing out 1
Installing Equipment 17 Run Tubing 5
Install BOP 3
Run WL 2
Nipple Down BOP 1
Set Well Plugs 1
Acidizing 1
Abandon Well 16 Pull Tubing 8
Set Well plugs 4
Killing 2
Nipple down tree 1
Pull/Drill plugs 1
SPE 39354
Distribution (%) of Operation Phase Failures
Primary Barrier Exp Drlg Dev Drlg Complete Prod W/O WL
Swabbing 25 40 4 0 22 3
Low mud wt. 30 30 10 2 18 4
Drlg break 62 31 0 0 2 0
Form break dn 42 42 0 5 8 0
Wellhead failed 12 8 3 45 18 0
Trapped gas 18 28 13 0 35 3
Distribution of percent of specific failed barrier in blow out.
Gas cut mud 40 23 13 0 20 3
X-mas tree fail 0 0 0 71 29 0
Cement setting 16 10 79 0 5 0
SecondaryBarrier
BOP fail - close 34 44 4 1 24 4
BOP fail after 34 27 13 2 10 3
BOP not instal 18 13 30 0 43 0
Frac csg shoe 15 65 8 4 8 0
Fail to stab val. 26 24 3 3 47 0
Csg leaks 42 17 4 33 3 0SPE 39354
But, wait…..
• To have a failure, several steps in our designand application methods must fail.
• To prevent the failure, you must understandthe reasons it happened and how the systemthe reasons it happened and how the systemworks.
• Take the case of a well blowout.……..
Well Blowout Event Pyramid
110 kicks taken
1blowout
Would 1 blowout per 733wells be a good number forrisk evaluation?
Could you use surveillance tosharpen it?
Actually, the blowoutnumber averaged0.15 blowouts per100 wells, but ranged
733 wells drilled
In the late 60’s and mid 90’s, the blowout rate was 1 blowout per 2500 wells.
In high volume years (early 80’s) the blowout rate jumped to 1 blowout per 366wells. Why? Inexperienced crews and faster pace are factors, but new drilling areasand increasing depth also had an effect.
100 wells, but rangedfrom 0.05 to over 0.4in specific areas.
Raw data from SPE 39354
First - Kicks Are Well Activity Specific
Drilling Kick Stats by Operation in
Progress
1000
1200
Num
berofkic
ks
0
200
400
600
800
1000
Drillin
g
Tripping
Out
Tripping
In
Cas
ing
Circ
ulating
Testing
Other
Operation in Progress
Num
berofkic
ks
SPE 19914
But, for a kick to become a blowout, a barrier must fail
Primary Barrier BO Secondary Barrier BO
Swabbing 158 BOP failed to close 78
Too low mud weight 50 Rams not seated 14
Drilling breakthrough / unexp. high pressure 45 Unloaded too quickly 13
Formation breakdown – lost circulation 43 DC / Kelly / TJ / WL in BOP 5
Wellhead failure 40 BOP failed after closure 66
Trapped / expanding gas 40 BOP not in place 43
Gas cut mud 33 Fracture at casing shoe 38
X-mas tree failure 23 Failed to stab valve / Kelly / TIW 34
While cement setting 20 Casing Leakage 23
Unknown 19 Diverter – no problem 21
Poor cement 16 String safety valve failed 19
Tubing leak 15 Diverter failed after closure 17
Improper fill-up 13 Form. breakdown / lost circ. 15
Tubing burst 10 String failure 13
Tubing plug failurel 9 Casing valve failed 11
Packer leakage 6 Wellhead seal failed 10
Annular losses 6 Failed to operate diverter 7
Uncertain reservoir depth / pressure 6 X-mas tree failed 7
SPE 39354
What warning signs were apparent? When are they seen?What are the contingencies?
UKCS Kick Data – All Wells1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 Total
orAvg.
NumberUKCS Wells
344 338 348 330 298 272 301 343 378 355 361 3668
Wells w/ kicks 34 32 45 41 34 27 39 38 45 39 36 410
% Wellsw/kicks
10 9 13 12 11 10 13 11 12 11 10 11%
SPE 56921
Kick frequency and the percentage of kicks that turn into blowoutsvary sharply throughout the world.
The percent of wells taking kicks doesn’t vary that much.
UKCS Kick Data - Workovers1995 1996 1997 1998 Total
orAvg
Estimated number ofworkovers
370 450 530 430 1780
Number of kicks during 5 10 3 2 20Number of kicks duringworkovers
5 10 3 2 20
Number of gas releases duringworkovers
1 2 1 6 10
% Workovers with kicks orreleases
2 3 1 2 2%
SPE 56921
UKCS Kick Data - Workovers1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 Total
Cased Hole /WorkoverKicks
7 10 11 8 5 9 5 8 20 6 5 94
?
SPE 56921
The number of kicks during workovers often has to be viewedover time to gain consistency. Low well population can skewthe numbers.
?
Understand the Data! – Two ways oflooking at drilling kick rate.
Alberta Kick Rate by Depth of Kick
20
25
Kic
kR
ate
,k
ick
sp
er
10
0w
ells
Alberta Kick Rate by Depth of Well
40
50
60
Kic
kR
ate
,k
ick
sp
er
10
0
0
5
10
15
0 to1000 1001 to 2000 2001 to 3000 3001 to 4000 GT 4000
Depth of Kick
Kic
kR
ate
,k
ick
sp
er
10
0w
ells
SPE 19914
0
10
20
30
0 to1000 1001 to
2000
2001 to
3000
3001 to
4000
GT 4000
Well Depth, m
Kic
kR
ate
,k
ick
sp
er
10
0
we
lls
Kicks may vary with activity, experience and costdrivers. Alberta Kick Study
• 10 year study (1979-1988), 62632 wells, 2457 kicks.
• Average kicks = 3.9 kicks per 100 wells.– Exploratory – 5.7 kicks/100 wells
– Development – 3.2 kicks/100 wells
• By Year:• By Year:– 1979, 4.0 kicks/100 wells
– 1982, 2.6 kicks/100 wells
– 1986, 4.8 kicks/100 wells (lowest well count)
– 1988, 4.1 kicks/100 wells
SPE 19914
Lowest profitmargin, poormaintenance,low personnelcounts,
Technical Risk Management ThroughSurveillance
• A routine surveillance plan is critical toefficient reservoir management.
• Surveillance gathered on a healthy well, is thebasis for diagnosing problems.basis for diagnosing problems.
• All of it fits under the depletion plan.
Intervention Sequence
1. Management understanding of the need and the rewards of a strong basemanagement program.
2. Continuous investigation (surveillance) of specific data
3. Assessment of data => understanding of problem / potential.
4. Creation of a fit-for-purpose solution => candidate selection refinement!
5. Consistent ranking of all candidates:5. Consistent ranking of all candidates:
– Possibility of success
– Return on investment
– Grouping to allow learnings-related workover program
– Availability of people, equipment, money and weather.
6. Post job review, feedback into understanding loop.
7. Results tracking, learnings sharing, management updates.
Asset Value Opportunity
Accelerated, high percentage reserverecovery is the primary driver behindeconomic operation.
We know the least about a reservoir whenwe locate, design, drill and complete thewells.
Surveillance during production will change
SPE 52968
Surveillance during production will changethe way we understand the reservoir – buthow do can we capitalize on it?
Asset Value Opportunity – BaseManagement
SPE 52968
What makes an exceptional wellworkcampaign?
• Success of well intervention campaignsdepend on:
– Quantity / quality of candidates.
– Knowledge and experience of field application– Knowledge and experience of field application
– Ability to monitor and learn from the wellwork.
Expendatures in Successful Well Work Program
Successful well work programs have all requiredactions listed and funded
Repair, 30%
Enhancement,
24%
Integrity, 27%
Surveillance,
13% Other, 6%Repair
Enhancement
Integrity
Surveillance
Other
SPE 88025
The Value of Well Work is Often UnnoticedUntil It is Done.
Production with & without Well Work
Pro
du
cti
on
Rate
Enhancement
Repair / Optimization
Base w/o Well Work12 % Decline
Time
Pro
du
cti
on
Rate Base w/o Well Work
20% Decline
Wellwork can accelerate recovery andadd reserves.
Production with & without Well Work
Pro
du
cti
on
Rate
Enhancement
Repair / Optimization
Base w/o Well Work12 % Decline
Time
Pro
du
cti
on
Rate Base w/o Well Work
20% Decline
Economic Limit
Added Reserves Recovered
25%
65%
40%
60%
80%
Norwegian Study of Reserve Recovery vs. Tree
Location
Data from Gulfax and Statfiord Fields in Norwegian North Sea, data provided by Statoil
0%
20%
40%
Wet Tree Dry Tree
Recovery
Reliability – what will be discussed
• Downhole and Surface Equipment
• Completion Types
• Workover Techniques
• Production Operations
• We will bounce back and forth because all are tiedtogether – the way a well is drilled and completedaffects its life span, but in a sometimes differentmanner than production operations.
Downhole Equipment Importance
Tracking Trends – two operators
Trends – Moving Averages
Optimization Effect on Failures
How?
What?
Continued
Failure Frequency - FPY
Completions and Equipment
• Completion design, age and specificconditions influence failure rate.
• Equipment improvements can be majorchange elements.change elements.
Equipment - Overall ScSSV Reliability -Sintef
Overall ScSSV Reliability w/ Time
20
25
MT
TF
(years
)
WR = wireline retrievable
TR = tubing retrievable
0
5
10
15
20
WR
1977-
82
WR
1982-
86
WR
1987-
89
WR
1989-
92
TR
1977-
82
TR
1982-
86
TR
1987-
89
TR
1989-
92
MT
TF
(years
)
SPE 26721
TR = tubing retrievable
ESS and OHGP’s havedramatically improved inreliability for some operatorsreliability for some operatorsover time.
Sand Control – the concept…..
• Sand control may be sand exclusion (no sandproduced) to sand management (where somesand is produced).
– They have sharply different failure rates– They have sharply different failure rates
– They have sharply different failure places
– They have sharply different failure costs
Very good slide from Shell Brunei – What range can you operate in?
Sand management – drill cheap wells and take care of sand at surface – but manage erosion.
!
Note that in the Shelldata that sand declineswith time, but bursts ofsand will be producedwhen system flowingparameters change –KEEP IT STEADY!
Offshore and Onshore Trends
• Failure and Intervention Frequency is verydifferent for on-shore, platform & sub-sea wells
Sub-Sea Intervention Estimates(mix of GOM, North Sea, Brazil and West Africa)
307 7 6
1 1
Hydrate Removal
SS Tree, Choke and Pod
ScSSV System
Gathering and Flow Lines
30
12128
8
8
7 7Paraffin & Asphaltenes
Recompletion & Water Control
Sand Control Repair
Fill Removal
Scale
Lift & Unloading
Annular Pressure Damage
Selected Interventions – Completion and Production Issues - Omits Abandonments.
Cautions
1. Failure data and failure perception is often an artifact of thedata source. A person’s memory is selective and biased.Trust the overall well file data, but be cautious of specificdata points.
2. Failure definition & explanation are frequently disputed.
3. Short life zones skew the data towards longer perceived3. Short life zones skew the data towards longer perceivedreliability.
4. New field/well data (<5 yrs) skew the data towards longerperceived reliability.
5. Limited well numbers skew the data all over the place.
6. Failure frequency is NOT intervention frequency. Failuresoften stumble along for years at reduced rates.
Failure Definition
• Which is failure?1. Sub 40 micron fines produced at full flow.
– No – if design was not to plug.
2. Sand produced at full well flow.– Yes – economics based on full flow
3. Well production possible but choked back– Still a failure – anytime production is limited.
4. Well intervention required– Depends – water control? open new zone?
Classifying Failures
• Design failures – poor design or data frac
• Application – pumping or Q/C problem
• Infant failure – within 30 days
• Production failure – during producing life• Production failure – during producing life
• Failure by subsidence – a disqualifier
• Fines production? – depends on size
Calculated Pressure Drop Through Frac Pack
in Campos Basin
2000
2500
3000
Dra
wd
ow
n,
psi
0
500
1000
1500
0 10 20 30 40 50 60
Wells
Dra
wd
ow
n,
psi
SPE 73722
1 Darcy
250 md
20,000 bpd, 100 ft screen,
calculated flux = 200 bpd/ft PL measuredflux = 700 bpd/ft
Flux as a production limit? Yes, but measure,don’t calculate it.
100 md
50 md
Localized hotspots fromlayered flow can destroyscreens
Weave Damage on an Eroded Screen
01/28/98
Hot spot plugging and subsequent erosion can occur anywherewhere a hot spot develops.
BP - Trinidad
Fracturing may help link layers and avoid “hotspots” near the wellbore.
Does it work the same in horizontal wells?
Problems for SC Completions
• Too thin or too thick gravel between screen andcasing in OHGP/CHGP. Min > ¾”, Max <2.5”?
• Access to wellbore in high rate wells.
• Not getting perforations clean before packing (acidprepacks worked pretty well)prepacks worked pretty well)
• Unpacked perforations in Frac packs and HRWP?
• Mobile fines with any screen or “tight” gravel(Saucier = 6)
• Abrasion, hot spots and plugging
• Shales > 10% of interval
Failure Causes – Sand Control
Design21%Flux
17%
Sand Control Failure Root Cause
Compaction12%
sand control infantmortality
12%
Sand control failureunclassified
38%
Sand Control - Some Background
• Much of the oil and gas production currentlybeing discovered and developed offshore willrequire sand management approaches.
• Some sand control methods have as little as -1 to• Some sand control methods have as little as -1 to+2 skins – Others generate +10 to +15 skins.
• Failure rate is NOT the same as intervention orrepair rate. Many fail, few are repaired.
• A failure is defined by inability to operate the wellat designed rates because of sand production.
Screen Failures – two main types
• Installation failures – damaged screen duringrunning.
• Production failure
– Usually most of the screen plugged with fines and– Usually most of the screen plugged with fines andthen flow erodes a hole.
– Less often – subsidence creates compression andscreen distortion.
A few things that cause screens to fail………
• Running screens– drag, sharp turns, windows, dope, shale,
• Pumping past screens– erosion, pressure, screenouts
• Pumping through screens• Pumping through screens– Fines in packing fluid, rate, volume
• Producing through screens - plugging– Fines in drill-in fluid, mobile fines, pressure drop
• Compaction loads
Top of screen 1 to 2 joints abovetop perfs or top of pay in openhole
Multi position gravel pack packerwith large crossover port forhigher rates (120% of tubingarea).
90 to 120 ft of blank pipe above thescreen – serves as a gravel reserve(along with the screen above thetop perf)
Annular clearance 1” to 3”between screen and casing oropen hole.
Slurry flow path pickled toremove dope, mill scale, mudand rust.
Undamaged Screen placed incorrect position – centralized.
holeopen hole.
Sump packer 5 to 10 ft frombottom perfs
Gravel displacementoutside perfs at least 45lb/ft – more can bebetter.
Washpipe inside screen 80% ofscreen ID
Perfs – 12 to 27 spf, DP or big holeand CLEAN!
Clean, low debris proppant sizedfor formation sand retention andmax permeability
Minimum blanks in screen meanminimum voids in pack.
Liquidreturn tosurface
slurryFailure points in the flow path duringfrac or gravel packing:
1. Crossover port
2. Casing oppositecrossover port.
3. The annular area between screen and casingwall.
a. Erosion from high velocity linear flow –a. Erosion from high velocity linear flow –minimal problem
b. Erosion from high velocity flow as the slurryenters a perforation.
c. Pressure drop in this area during high rateflow (fracs) can collapse screens – problemsare very rare, but watch clearances.
Flow Capacity of Clean Screen
6
8
10
12
Pre
ss
ure
Dro
p,p
si
2-3/8"
2-7/8"
0
2
4
6
0 5000 10000
Flow Rate, BPD/ft
Pre
ss
ure
Dro
p,p
si
2-7/8"
3-1/2"
Sand Control Reliability - problems
• Skin damage– Reservoir-to-wellbore limits
– Invasion of fines into gravel
– Crushing/breaking of gravel– Crushing/breaking of gravel
• Physical Damage– Screen Running Damage
– Erosion during production
– Corrosion – from produced and injected fluids
Primary Erosion Locations
• Directly opposite perforations
• sharp turns in the flow path
• where gas velocity is maximum
• eddy current and similar patterns• eddy current and similar patterns
• constrictions in the flow path
WirewrapWirewrap Screen Erosion w/ AirScreen Erosion w/ Air
Erosion tests by Baker - erosion failure can happento any screen – any design. Correct Application isabsolutely critical.
Damage created by running and pulling screen can result in immediate failure.
Failed screen during an Angolawater injection DST. Load setdown on screen caused amechanical burst.
Design Learnings
1. Crossover ports should have an area at least as large as the tubing area,preferably 130%.
2. Crossover ports should be shaped to assist the slurry direction changeand minimize turbulence.
3. The area of the screen/casing annulus should be 20% larger than thetubing – keep pressure drop below about 500 psi/100 ft.tubing – keep pressure drop below about 500 psi/100 ft.
4. Zones with very high permeability streaks may bridge the annulus withdehydrated sand plugs – special design is required.
5. Never stand screens in the derrick.
6. Use a screen table to run.
7. Adequate make-up room needed at joints, but minimize blanks wherevoids may occur.
Some Database Learnings
• Screen type as a failure factor in frac packing isovershadowed by:
– Running damage to the screen
– Screen-to-casing clearances– Screen-to-casing clearances
– And, “maybe” how pack is placed after frac.
Classic Failure Rate
25
30
35
40
45
50
#F
ailu
res
Early Failure –usually < 30 days.
Wearing out– period ofaccelerated failures
0
5
10
15
20
25
0.1 1 10 100
Time
#F
ailu
res
Long term stability
Completion Failure Rate by Age and Completion
Type
10
12
14
Co
mp
leti
on
sin
tha
tA
ge
Gro
up
Th
at
Fa
il(S
an
dC
on
tro
l
SOC=14/124CHGP=3/26
SOC=10/28
Sand Control - Production Failures
0
2
4
6
8
10
0 2 4 6 8 10 12
Completion Age, yrs
Co
mp
leti
on
sin
tha
tA
ge
Gro
up
Th
at
Fa
il(S
an
dC
on
tro
lF
ailu
res
) SOC
CHGP
OHGP
FP
CHGP =2/45
FP = 0/153
OHGP=0/18
FP=3/766
9/144
4/81
FP=0/27
FP = 0/70
OHGP = 0/2
CHGP 4/304
Snap Shot of Sand Control Failures - 2 yrs oldType ofCompletion
#Wells
Wellyears
DesignFailure
ApplicationsFailure
EarlyFailure
ProductionFailure
% Attempts % Attempts % Attempts Failures /well / yr
Screen Only 183 783 0.6 0.0 0.6 0.06
Cased HoleGravel Pack
369 1514 0 2.2 0.8 0.011Gravel Pack
Open HoleGravel Pack
175 507 0 9.7* 0.6 0.016*(<0.01?)
High RateWater Pack
187 544 0 0.5 0.5 0.009
Frac Packs 844 3369 1.7 2.4 0.2 0.004
Total Wells 1758 1617
* Skewed by early learning failures, probably cut at leastin half for better operators
Tubular Failures
• Mechanical
– Running problems
– Performance over time
– Collapse and Burst from operational forces– Collapse and Burst from operational forces
• Trapped annular pressuring
• Lift problems
• Corrosion
Well Failure Statistics
20%
25%
30%
35%
'94-2000'
'90-'93
We
llsD
eve
lop
ing
Leak
s
0%
5%
10%
15%
20%
0.0 5.0 10. 15. 20. 25. 30. 35. 40.
'90-'93
'80-'89
'70-'79
'58-'70
Vastar Putnam
We
llsD
eve
lop
ing
Leak
s
Well Life Prior to Casing Leak, Years
Note that well life, time period of completion and operator makessignificant differences in failure rate.
0.20
0.30
0.40
0.50
0.60
0.70
Failure
Rate
Casing Field Failure History
1990's
1980's
Con
nect
ions
Collaps
e
Wea
r
Brittle
unkn
own
1990's
0.00
0.10
0.20
Failure Mode
Time
Period
Source – Brian Schwind - PPI
Some failures have been decreased with time because of knowledge growth. Somefailures are sharply increased as new areas (deep water and increasing depth) areentered.
What happened?Corrosion?Change of operating conditions wasa major factor.
Deep Water Well Pipe Collapse
A simple mistake like forgetting to fill the pipe whilerunning (closed-ended) into a mud-filled riser cancontribute to pipe collapse.
Trapped Pressure Also a ProblemTrapped annular pressure from leaks or outside charging can bea factor. The problems include inner pipe collapse and outerpipe burst. Straight API strength ratings may be altered bycorrosion (inside and outside), pressure support from otherzones (increasing burst and/or collapse resistance), wear,tectonic loads, etc.)
Downhole Camera Inspection
Mechanical Caliper
What happens when the tubing isdropped in the well?
Mechanical Caliper
Abrasion Damage
Generally a problem inolder wells, deviated wellsand wells with a history ofmilling or fishing. It is verydifficult to spot and tofactor effect on pipestrength or equipmentstrength or equipmentreliability.
Erosion – by Formation Sand
A by-product of sand production in many cases. Thisone started with a small leak. Erosion is one of thefastest failure causes and can work to acceleratecorrosion with even very small amounts of solids in thefluids.fluids.
Control Lines
Running and protecting control lines is achallenge. Fishing them is even morechallenging.
Ice DamageIcing in wells – can be from weather or Joule-Thompson coolingof gas expansion.
Monobore:mixed grades,same weight
Mixed gradesand weights
Mixedweights,samegrade
Casing Design Options – think about running and setting packers.
Small diametersSmall diametersat the top of thewell may prevententry by somepackers.
5/26/2010 126
Allowing Tubular Movement
• Usually incorporate a PBR - polished borereceptacle, for a “stinger” or seal assembly toslide through.
• Shoulder out on the PBR - if it can move, it will• Shoulder out on the PBR - if it can move, it willeventually leak.
• Seals must match operating extremes as wellas general conditions.
5/26/2010 127
Wear Patterns in a Well. Why?
0.55
0.6
Re
ma
inin
gW
all
Th
ick
ne
ss
,in
.
Distribution of Wear in Recovered 9-5/8", 53.5 lb/ft, Q-125 Casingwith Initial 0.545" wall
Crescent Shaped Wear
0.3
0.35
0.4
0.45
0.5
0 5 10 15 20 25 30 35 40 45
Re
ma
inin
gW
all
Th
ick
ne
ss
,in
.
Joint Number
Uniform Wear
Crescent Shaped Wear
Corrosion
• Corrosion Basics– General corrosion theory
– Corrosion examples
• Specialty Problems• Specialty Problems– CO2 and H2S
– O2 in sea water injection
– Acid Treatment
– Packer Fluids
Major Causes of Corrosion
• Salt water (excellent electrolyte, chloride source)
• H2S (acid gas with iron sulfide the by-product)
• CO2 (Major cause of produced gas corrosion)
• O• O2 (key player, reduce any way possible)
• Bacteria (by products, acid produced)
Other Factors
• pH
• Chlorides (influences corrosion inhibitor solubility)
• Temperature (Increase usually increases corrosion)
• Pressures (CO2 and H2S more soluble in H20)Pressures (CO2 and H2S more soluble in H20)
• Velocity - important in stripping films, even forsweet systems
• Wear/Abrasion (accelerates corrosion)
• Solids – strips film and erodes metal
Chemical Corrosion
• H2S– weak acid, source of H+
– very corrosive, especially at low pressure
– different regions of corrosion w/temp.
• CO2• CO2– weak acid, (must hydrate to become acid)
– leads to pitting damage
• Strong acids - HCl, HCl/HF, acetic, formic
• Brines - chlorides and zinc are worst
O2 Corrosion
Dissolved Gas Effect on Corrosion
Overa
llC
orr
osio
nR
ate
of
Carb
on
Ste
el
There is no corrosion mechanism more damaging on a concentration basis than oxygen – smallamounts of oxygen, water and chlorides can ruin a chrome tubing completion in a few months.Injection wells are the most severely affected – minimise oxygen and don’t use chrome pipe ininjectors.
20 ppb O2 limit for seawater incarbon steel injection tubulars.
0
5
10
15
20
25
0 1 2 3 4 5 6 7 8
Overa
llC
orr
osio
nR
ate
of
Carb
on
Ste
el
O2
CO2
H2S
Dissolved Gas Concentration in Water Phase, ppm
0 1 2 3 4 5 6 7 8
0 100 200 300 400 500 600 700 800
0 50 100 150 200 250 300 350 400
O2
H2S
CO2
carbon steel injection tubulars.13Cr is CO2 resistant but verysusceptible to pitting corrosionin aerated brines. 5 ppb O2 issuggested as a limit, but eventhese levels have not beenconfirmed.
5/26/2010 133George E. King, Engineering
GEKEngineering.com
REMOVAL OF “PROTECTIVE” FILM
Corrosion - Best Practices
• Adopt a corrosion managementstrategy.
• Be aware of corrosion and erosioncauses.
• Completion planning must reflectcorrosion potential over well’s life.
corrosion in tubing exacerbated byabrasion from wireline operators.
corrosion potential over well’s life.
• Develop maintenance programs,measure corrosion.
• Know the corrosion specialists.
• Ensure inhibitors are compatible withmaterials and the reservoir!
• If tubing corrosion is suspected, DONOT bullhead fluids in the formation.
1970’s Industry Study of Failures
Method % of Failures
Corrosion (all types) 33%
Fatigue 18%Fatigue 18%
Brittle Fracture 9%
Mechanical Damage 14%
Fab./Welding Defects 16%
Other 10%
Same factors still a problem -
Causes of Petroleum Related Failures(1970’s study)
Cause % of Failures
CO2 Corrosion 28%
H2S Corrosion 18%
Corrosion at the weld 18%
Pitting 12%
Erosion Corrosion 9%
Galvanic 6%
Crevice 3%
Impingement 3%
Stress Corrosion 3%
Corrosion Types
• Galvanic – a potential difference between dissimilar metals in contactcreates a current flow. This may also occur in some metals at the grainboundaries.
• Crevice Corrosion – Intensive localized electrochemical corrosionoccurs within crevices when in contact with a corrosive fluid. Willaccelerate after start.accelerate after start.
• Pitting – Extremely localized attack that results in holes in the metal.Will accelerate after start.
• Stress Corrosion – Occurs in metal that is subject to both stress anda corrosive environment. May start at a “stress riser” like a wrench markor packer slip mark.
Corrosion Types
• Erosion Corrosion – Passage of fluid at high velocity may remove
the thin, protective oxide film that protects exposed metal surface.
• Hydrogen Sulfide Corrosion – H2S gas a water creates an acid
gas environment resulting in FeSx and hydrogen.
• Hydrogen Embrittlement – Atomic hydrogen diffuses into the• Hydrogen Embrittlement – Atomic hydrogen diffuses into the
grain boundary of the metal, generating trapped larger molecules ofhydrogen molecules, resulting in metal embrittlement.
• Hydrogen Corrosion – Hydrogen blistering, hydrogen
embrittlement, decarburization and hydrogen attack..
CO2 Partial Pressure
• Severity is a function of the partial pressure
– 0-3 psi - very low – non chrome use possible
– 3-7 psi – marginal for chrome use
– 7-10 psi – medium to serious problem– 7-10 psi – medium to serious problem
– >10 psi – severe problem, requires CRA even forshort term application.
Partial pressure is the mole fraction of the specific gas times the total pressure. If the CO2 moleconcentration is 1% and the pressure is 200 psi, the partial pressure is 0.01 x 200 = 2 psi.
CO2 corrosionCO2 partial pressure vs. corrosion. Notethat mpy or mills per year of total wear maybe low but pitting damage can be very high.
CO2 localised attack in 7” productiontubing
Severe CO2 corrosion in tubing pulled from a well. One reason for the attack was that thetubing was laying against the casing, trapping water that was replenished with CO2 fromthe gas flow.
Thinned and embrittledtubing twisted apartwhen trying to breakconnection during atubing pull.
Corrosion weakened pipe – large areas can be affected.
This is the starting point – but whatcaused the break? Clues are foundin the well environment, the historyand the area surrounding the break.
CO2 CORROSION ISOPLOT
0.8
0.9
1.0
pH 5
0.9 - 1.0 mm/y 0.8 - 0.9 mm/y 0.7 - 0.8 mm/y 0.6 - 0.7 mm/y 0.5 - 0.6 mm/y 0.4 - 0.5 mm/y
30 40 50 60 70 80 90 100 110 120 130 140 150
-4
-3
-2
-1
0
1
0.0
0.1
0.2
0.3
0.4
0.5
0.6
0.7
Temperature, degC
Log(Pco2)
0.4 - 0.5 mm/y 0.3 - 0.4 mm/y 0.2 - 0.3 mm/y 0.1 - 0.2 mm/y 0.0 - 0.1 mm/y
07-01: What the liner looked like
• Well completed on 1/15/98
• 2-7/8” L-80 liner
Source – Jennifer Julian, Alaska BU
Liner Corrosion-7-01
• Lessons learned:– Smaller tubulars corrode/erode faster than larger
tubulars
– Before doing a RWO, strongly consider a linercalipercaliper
– Production response to corroded calipers can bevery gradual (i.e. they don’t look “broken”) withproblems occurring with steep changes in gasproduction.
– Run chrome liners.
Source – Jennifer Julian, Alaska BU
Mills/per year or mm/yr may not be a goodindicator when the metal loss is in pitting.
Trench corrosion common from CO2 attack.
Chloride Stress Cracking
• Starts at a pit, scratch or notch. Crackproceeds primarily along grain boundaries.The cracking process is accelerated by chlorideions and lower pH.ions and lower pH.
Stress Sulfide Corrosion
• Occurs when metal is in tension and exposedto H2S and water.
• Generates atomic hydrogen. Hydrogen movesbetween grains of the metal. Reduces metalbetween grains of the metal. Reduces metalductility.
Grading of pipe is useful, but doesn’t tell the whole story – e.g. N-80 and L-80.
Domain Diagram for C110
Domain Diagram for Super 13Cr
pH 4.5
5.5
ACCEPTABLE
0.03bara
pH 4.5
5.5
ACCEPTABLE
0.03bara
3.5
0.001 0.01 0.1 1.0
pH2S (bara)
Domain Diagram For The Sulphide Stress Cracking Limits
Of 95ksi Super 13Cr Alloys In High Chloride (120,000 ppm Cl-) Waters
UNACCEPTABLE
FURTHER ASSESSMENT REQUIRED
3.5
0.001 0.01 0.1 1.0
pH2S (bara)
Domain Diagram For The Sulphide Stress Cracking Limits
Of 95ksi Super 13Cr Alloys In High Chloride (120,000 ppm Cl-) Waters
UNACCEPTABLE
FURTHER ASSESSMENT REQUIRED
Hydrogen Sulfide Corrosion
• Fe + H2S + H20FeSx + H2 + H2O
• FeS - cathode to steel: accelerates corrosion
• FeS is a plugging solid
• Damage Results• Damage Results– Sulfide Stress Cracking
– Blistering
– Hydrogen induced cracking
– Hydrogen embrittlement
H2S corrosion is minimized by sweetening the gas (knocking the H2S out or raising pH.
SSC Failure of Downhole TubularString in Louisiana
Video
Crevice Corrosion• The physical nature of the crevice
formed by the tubing to couplingmetal-to-metal seal may produce alow pH aggressive environmentthat is different from the bulksolution chemistry – hence amaterial that looks fine when testedas a flat strip of metal can fail whenthe test sample (or actual tubing)the test sample (or actual tubing)includes a tight crevice.
• This damage can be very rapid inwater injection wells, wells thatproduce some brine or in wellswhere there is water alternating gas(WAG) sequencing – causingfailure at the metal-to-metal seals ina matter of months.
O2 Corrosion
Dissolved Gas Effect on Corrosion
Overa
llC
orr
osio
nR
ate
of
Carb
on
Ste
el
There is no corrosion mechanism more damaging on a concentration basis than oxygen – smallamounts of oxygen, water and chlorides can ruin a chrome tubing completion in a few months.Injection wells are the most severely affected – minimise oxygen and don’t use chrome pipe ininjectors.
20 ppb O2 limit forseawater in carbon steelDissolved Gas Effect on Corrosion
0
5
10
15
20
25
0 1 2 3 4 5 6 7 8
Overa
llC
orr
osio
nR
ate
of
Carb
on
Ste
el
O2
CO2
H2S
Dissolved Gas Concentration in Water Phase, ppm
0 1 2 3 4 5 6 7 8
0 100 200 300 400 500 600 700 800
0 50 100 150 200 250 300 350 400
O2
H2S
CO2
seawater in carbon steelinjection tubulars.13Cr is CO2 resistant butvery susceptible to pittingcorrosion in aeratedbrines. 5 ppb O2 issuggested as a limit, buteven these levels have notbeen confirmed.
A split in the side of 5-1/2”casing. Cause was unknown –mechanical damage (thinningby drill string abrasion) wassuspected.
Wear Damage
Abrasion by solids, gas bubbles or liquid droplets may significantly increase corrosion bycontinuously removing the protective oxide or other films that cover the surface following theinitial chemical reaction.
Most graphs do not show the effect of too low a velocity on the corrosion rate. When thesurface is not swept clean, biofilms can develop or the surface liquid layer may saturate withCO2 or other gas, increasing corrosion. Minimum rates are about 3.5 ft/sec for clean fluids.
Note the effect ofincreasing flowing fluiddensity on corrosionrate.
Also – presence of solidsAlso – presence of solidsin the flowing fluids verysignificantly lowers themaximum permissibleflow rate.
Corrosion increases after water cutreaches 10 to 20%. The cause isremoval of the protective oil film. In thethird phase, the pipe is completelywater coated and corrosion ratebecomes more constant.
Wetting of the surface bywater significantlyaccelerates corrosion.
Top, Left: Chrome pipe after acidizing with the proper inhibitorand inhibitor intensifier.
Bottom, Left: Chrome pipe after acidizing with a marginalinhibitor.
Bottom, Right: Chrome pipe after acidizing without aninhibitor.
15% HCl, 2 hour exposure
WeldsThe heating that occurs during the welding process will cause theweld metal and the heat affected zone around the weld to bephysically different from the surrounding, original metal.
An anode is created by this difference.
An anode can start here or here.
Heataffectedzone
Weld metal (added anddifferent from originalbase metal)
Base metal
Bacterial deposits on injection tubing. Pittingunder the bacterial colony can be severe.Anaerobic
SRB’s - sours the well/reservoirIron Fixers - slime and sludgeSlime Formers - formation damage
–
Erskine – Failure of 25Cr Duplex SS
Source – BP Corrosion – John Alkireand John JW Martin
Many of the super alloy failureshave been linked backed to thebrines used for completions.
Cracking initiated at a stressriser – impact or wrenchmark.
Bacterial CorrosionBacterial Corrosion
Co2 corrosion in box, just past gap in coupling.
Parted coupling – CO2 corrosion – note trenches and pits.
Severe O2 corrosion in a surface line, just downstream of a connection.
Sacrificial anode (magnesium) from an offshore platform. This was a round bar stock anode.
Sacrificial Anodes - Galvanic Series in SeaWater
1. Magnesium
2. Zinc
3 soft aluminum
4.cadmium
5. hard aluminum
6. steel
7. stainless steel (300 series)
8. lead
9. brass and bronze
10. Inconel
11. Hasteloy C 276
Controlling Corrosion
1. Maintain high pH
2. Control gas breakout
3. Use passive metals
4. Remove Oxygen
5. Control velocities
6. Lower chlorides
7. Bacteria control
8. Acid/brine use considerations and alternatives
9. Liquid removal
10. Inhibitor injection
11. coatings
Acid Inhibitor Mixing
• Set up for “rolling” the tank, not slowcirculation - upper layer must be mixed in
This Won’t Work!This Won’t Work!
pump
Unless youget the toplevel caughtin thecirculation
Acid Inhibitor Mixing
• Check the inhibitor layer is possible
This will workThis will work
pump
Inhibitorpulled in
Inhibitor Mixing
• What will work?
– Air sparging orrolling the tankwith gas
– paddle mixing that createsa vortex
mixer
– vigorous rolling
• Effect of oxygen in acid -– oxygen increases corrosion
– oxygen saturation in acid is 7 parts per billioneffect is limited
Chromium
• Increasing Cr content of the alloy increasesthe Cr content (and film resistivity) ofcorrosion layer. Above 10% Cr in alloy,composition of layer is constant. Why usecomposition of layer is constant. Why usemore???? - chemical resistance.
• For 13% and 22% Chrome tubulars, criticalerosion velocities are twice carbon steels inCO2.
Tubular Selection Criteria – someconsiderations
• Embrittlement– hydrogen
– chloride stress cracking
• Weight Loss Corrosion– H2S-CO2-H2O-NaCl systems– H2S-CO2-H2O-NaCl systems
– CO2-H2O-NaCl
• Localized Corrosion
• Acidizing
• Galvanic
• Strength
• Cost and availability
Crack in the casing immediately below the wellhead.Probably due to a minor defect in the tubular andperhaps compounded by wellhead stress.
Equipment Approx Failure Ratefailures/well/yr
Packer 0.004
Rough Downhole Failure Rates
0.009
Cement/lap 0.012
SS Pods 0.023
SS SSSV 0.014
SS SSSV issues 0.024
SSSV
Flow Assurance
• Paraffins and Asphaltenes
• Scales
• Emulsions
• Hydrates• Hydrates
Wax Deposition impacts operations
Reduces throughputIncreases pressureReduces revenueIncreases risks opening pig receivers
Muge Erdogmus - BP
Wax in Oilfield Fluids
In solution No immediate problem
In suspension Can lead to flow problems, i.e. viscosityIn suspension Can lead to flow problems, i.e. viscosity
DepositedBlock or restrict flow in wells/flowlines/export pipelines
Gel Formation Can lead to restart problems – worst case is
totally blocked pipeline $$$$
Muge Erdogmus - BP
HARD/ SOFT WAX DEPOSITS
SOFT DEPOSITS• Formed under low shear• Formed under low heat flux• Open waxy structure• Contain large amounts of
entrapped oil• Become harder with time in
HARD DEPOSITS• Formed under high shear
• Often contain large amountsof asphaltene
• Wax inhibitor itself mightcause hard deposit!!!• Become harder with time in
flowing environmentcause hard deposit!!!
Generally:Larger VolumeEasier to Remove
Generally:Lower VolumeHarder to Remove
Muge Erdogmus - BP
Frictional pressure loss
In single phase flow frictional pressure drop isgiven by:
f L r u2
DPf = –––– ––––––d 2
where:d 2
where:f = friction factor (Darcy-Weisbach)L = length of piped = pipe diameterr = fluid densityu = fluid velocity
f is proportional to Re (and hence viscosity
Muge Erdogmus - BP
Viscosity of a Non-Newtonian Crude
Muge Erdogmus - BP
Controlling Wax Deposition
StrategyAvoidance:
Prevent wax fromforming / sticking
Manage:
Tool KitThermal:
Insulation, heat, flushing
Chemical:
Inhibitors, solventsManage:
Control rate andclean at acceptablefrequency
Remediate:Intervene whennecessary
Inhibitors, solvents
Mechanical:
Pigging, scraping
Novel / Black Box:
Ultrasonics, magnets
Muge Erdogmus - BP
High Thermal Insulation Systems
Inner Pipe
Water Stop / Spacer
Annulus
Field Joint
Inner Pipe
Water Stop / Spacer
Annulus
Field Joint
Aim to maintain fluid arrival temperatures at surface above WAT
Pipe-in-pipe
Pipe bundles
Outer Pipe
AnnulusInsulation
Outer Pipe
AnnulusInsulation
Muge Erdogmus - BP
Wax Chemical Additives
• Crystal modifiers– Distort wax crystals, often through co-crystalisation, inhibiting
further growth– Pour point depressants– Wax inhibitors
• Dispersants– Penetrate wax deposit, disperse and mobilise particles– Penetrate wax deposit, disperse and mobilise particles
• Detergents– Render wax water wet and prevent agglomeration
• Bugs– Consume heavier fractions
Muge Erdogmus - BP
HeatingFor avoiding wax when system is cold or melting deposited wax
Heat Tracing
IPB - Integrated ProductionBundle
Skin Effect CurrentTracing
Integrated ProductionUmbilical
Direct ElectricHeating System
S
Electrical Heat TracingFlowline
Muge Erdogmus - BP
Hot Oiling
• Useful in flowlines or equipment
• An increase in the oil temperature of only 10°C will
quickly soften wax
• Achieving the Wax Melting temperature is not• Achieving the Wax Melting temperature is not
normally necessary in a flowing system
• Should not be used in wells unless plugs are set to
keep the wax saturated hot oil out of the lower well
(no more than 10 joints down).
Modified from Muge Erdogmus - BP
Pigging• Scraper pig is most common method of removing wax
deposits
• Pig is swept along by the oil flow and mechanicallyscrapes wax off the walls
• A small amount of oil bypasses the pig to disperse theremoved solids and prevent a wax slug from forming
• In a well, sucker rods and wireline scrapers do asimilar jobsimilar job
• Foam pigs may be used initially if thick deposits are– These deform to fill pipe, but can build up a slug in front
• Chemical pigs may be useful.
Modified from Muge Erdogmus - BP
Asphaltenes• Defined as Pentane insoluble
• Heaviest and largest molecules in the hydrocarbon mixture
• Characteristic black color
• Become unstable with significant changes in density,usually due to changes in pressure
• Oils likely to exhibit precipitation have high gravities, low• Oils likely to exhibit precipitation have high gravities, lowasphaltene contents, are highly undersaturated and haveunfavorable Resin to Asphaltene or (Sat. + Asp.) / (Aro. +Res.) ratios.
• Precipitation can also occur due to commingling
• Problem Avoidance: Pressure maintenance in reservoir.Pressure/density maintenance during sample handling.Avoid volume changes.
Precipitated Solids Filter ExperimentsAsphaltene Phase Diagram
Saturation Pressure Curve
Upper Asphaltene OnsetSingle Phase Oil Region
No Asphaltene Precipitation
Asphaltene PrecipitationReservoir P&T
Pre
ssu
re
Temperature
Two Phase Liquid and Gas Region
Separator P&TSeparator P&T
Lower Asphaltene Boundary
Pedcor- Corelabs
Asphaltene Stability
• Maltenes and resins form the micelle
• Asphaltene is the small platelet (35A) held inthe middle of the micelle
• Dispersed platelets are not usually a problem• Dispersed platelets are not usually a problemalthough the oil may have a high viscosity
• When micelles are upset and broken, theplatelets coagulate and form a mass.
One form of asphaltene – hard balls of dry asphaltene platelets thatadhere to each other. Other forms are viscous tar-like masses
World Wide Crude Oil Chemical Compositions (SARA)Hydroc arbon Numbe r
Field Asphaltene Re s in Aro matic Saturated Total of
(Wt %) (Wt %) (Wt %) (Wt %) (Wt %) Sample s
Athabas ca 23.3 28.6 32.1 15.9 48.1 15
Wabas ca 21.6 30.6 32.1 15.6 47.7 7
Peac e Rive r 48.7 23.2 20.5 7.6 28.1 3
Cold Lake 20.6 28 30.5 20.9 51.4 7
E. Ve ne zue la 12.6 32.4 36.4 18.6 55 5
Average on 22.9 30.6 30.4 16.1 46.5 46
46 Heavy Oils46 Heavy Oils
PB HOT (EOA) 14.13 13.37 28.1 44.4 72.5
PB HOT (WOA) 10.38 20.42 28.23 40.97 69.2
W. Ven. (ne ar 13.2 12.9 38 35.9 73.9
HOT)
Co nve ntio nal 14.2 28.6 57.2 85.8 517
Normal Oils
PBU Normal 16.52 1.9 31.93 49.67 81.6
Oil 18.42
Schrader Bluff 4.9 29.0 24.7 41.5 66.2 15
Asphaltenes
• precipitated by:
– CO2
– acid
– pH– pH
– turbulence
– chemical shift that upsets micelle
Microscopic photos of asphaltene aggregationMicroscopic photos of asphaltene aggregation
Rice U. - P. Zhang
O - Nothing could be seen o - Fine particles
x - Tiny aggregation X - Large aggregation
Ultra low viscosity oils, usuallyasphaltic or paraffin based, present aspecial set of problems in damagerecognition and treatment.
Few methods are successful inprevention. Solvents are common buthave poor effectiveness at removal.
Asphaltic Sludges
• Form very viscous masses, often after contactwith spent acid; frequently catalyzed by iron
• Sludges are serious problems because theycannot be easily removed.cannot be easily removed.
• Test the oil with spent acid and 1000 ppm ironbefore acidizing any oil reservoir. Use anti-sludge and an effective iron control additive.
Scales
• Usually a precipitate from a brine thatbecomes saturated with a material due to achange in the conditions within a well.
• Scale precipitation may be driven by mixing• Scale precipitation may be driven by mixingincompatible waters, but can also be causedby out-gassing, shear, turbulence, andtemperature and pressure loss.
Scales
• calcium carbonate - upset driven
• calcium sulfate - mixing waters, upset, CO2
• barium sulfate - mixing waters, upset
• iron scales - corrosion, H S, low pH, O• iron scales - corrosion, H2S, low pH, O2
• rarer scales - heavy brines
Some scales form in layers, often driven by an “upset” in the flow dynamics of the system.These deposits can form almost anywhere, on any surface, but the deposits are usually justdownstream of the location of an upset in the flow system. The location of the scale is often anindicator of what is causing the precipitation.
Calcium carbonate scale deposit showing ability to “cleave” along the layer boundaries. Unusualshape was from deposition on a flapper of a SSSV.
Calcium sulfate scale from slow growth in a high water cut reservoir.
A rapidly formed deposit of calcium sulfate formed after an acid was mixed with a scaledissolver chemical that had removed a deposit of calcium sulfate scale at the perforations.
Calcium Sulfate scale that completely blocked a section ofdownhole tubing – this piece was from a connection.
Scale crystals formed slowly in a gathering line.
Scale Location
• at pressure drops - perfs, profiles
• water mixing points - leaks, flood breakthru
• outgassing points - hydrostatic sensitive
• shear points - pumps, perfs, chokes,• shear points - pumps, perfs, chokes,
• gravel pack - formation interface
Barium SulfateScale from a
Scale may appear at the surface first –or last. All depends on the scale and
flowing conditions.
Scale from aNorth SeaProductionSeparator
Scale at the gravelpack / formation
interface.
Calcium carbonate scale wasfound at the interface of thefound at the interface of thegravel pack interface with theformation. The precipitationtrigger was pressure drop,resulting in out-gassing of CO2with an accompanying pHincrease.
Scale Prediction
• Chemical models - require water analysis andwell conditions
• Predictions are usually a “worst case” - this iswhere the “upset” factor comes in.where the “upset” factor comes in.
– added shear - increased drawdown, chokechanges, etc.
– acidizing
– venting pressure
Scale Deposition – mostly in top of well
Very Even Accumulation
Beware of predicting deposition points until youunderstand unloading efficiency. Workover hydraulics
in wellbores are critical.
Scale deposition points or “slug recovery” of debris?slug recovery” of debris?
Putting it to use.
• Localized scale deposition may be from:
– Temperature or pressure crossing precipitationthreshold at a specific point.
• Could it be changed by altering rate, temp loss or holding• Could it be changed by altering rate, temp loss or holdinga bit more pressure?
– Might be affected by shear at a restriction
• SSSV, collapse, nipple profile, fluid mixing, etc.
• Consistent scale deposition along the lengthusually from basic incompatability.
Emulsions
• Multiple phases that do not separate quickly;usually requires an energy source.
• If oil and water do not separate quickly, thenlook for the stabilizing mechanismlook for the stabilizing mechanism
• Emulsions are frequently blamed for damage,however, most emulsions are formed in thetubing or lift system by gas breakout or addedenergy.
Types of Emulsions
• oil-in-water
• water-in-oil
• gas-in-water (foams and froths)
• solids-in-liquids (muds, etc.)• solids-in-liquids (muds, etc.)
• Over twenty different combinations that canbe called emulsions.
Energy Sources
• lift system
• gas breakout
• shear at any point in the well
• choke• choke
• gas expansion
Stabilizers
• surfactant (film stiffeners)
• solids (silt, rust, wax, scale, cuttings)
• emulsion or component viscosity (preventsparticle or droplet contact)particle or droplet contact)
Widely
Deformation
Changes in Fluid Viscosity with Change in Internal Phase of Dispersed or EmulsifiedFlow
Increasing internal fraction of the “emulsion”
52% 74% 96%
Viscosity
WidelyDispersed Contact
Inverted
Expansion of gas occurs as the gas rises from the bottom of the well. Theexpanding gas can entrain and carry liquid with it if the flow rate reaches criticalvelocity (the velocity necessary to lift liquid).
2500 ft
1075 psi
Remember – the volume of the gas bubble (andindirectly the velocity of the upward flowing fluid) iscontrolled by the pressure around it. This pressure isprovided by the formation pore pressure andcontrolled by the choke and other back pressure
5,000 ft
2150 psi
controlled by the choke and other back pressureresistances.
The type of flow pattern changes with the expansion of the gas. One or more of the flowpatterns may be present in different parts of the well. The flow patterns may explain differencesin lift, corrosion and unloading.
Mist Flow – external phase is gas with a small amount ofliquid
Channel or annular flow
Slug or churn flow
Piston flow
Bubble flow
Single phase liquid flow
Depth andPressure
Hydrates
• Crystalline or clathrate materials of frozenwater and gas. Can be formed at temps over32oF (0oC) and on pressure reduction.
Press
Temperature
hydrates
no hydrates
saltier water
Hydrates – clathrates of gas and water
Source – Muge Erdogmus
Hydrate Phase Behavior
Pre
ssu
reHydrocarbon
Liquid + Water
Hydrate +WaterHydrate
+ Ice
Temperature
Pre
ssu
re
+ Ice
Ice +Gas
Liquid Water +Hydrocarbon Gas
Hydrate FormationLocus
Solid polymer lumps or “Fisheyes” and microgels filtered from liquid HEC polymer.Microgels or “fisheyes” after straining a liquid HEC dispersion through a 200 mesh screen in ashear and filter operation for gravel pack fluid preparation.
FacilitiesPressure
Flow LineBack-pressure
Hydrostatic
Wellhead Pressure Chokes• Reservoir (e.g. coning)• Sand-control• Erosion constraints• Commercial e.g. Gas contract• Facility Constrained e.g Gas Handling
Exportlosses
The Physics !
P Reservoir - targetTubing FrictionPressurelosses
BHFP
Near-Wellbore Lossese.g. Skin and turbulence
P Draw-down[‘Good’ Pressure Loss]
P Reservoir - actual
losses
BP
Support Slides
• Pipe Banding, Grading and Re-use
Safety Moment – Chains help you go.They don’t keep you from skidding.
Some Basic “Formation Damage” Causes
Completion Stimulation ProductionProblems - 1
ProductionProblems - 2
DepletionEffects
Particles frommuds & brines
Poor selection orapplication
Wetting Hydrates Natural fracclosure
Fluid invasion offormation
Poor well-to-formation link
Water blocks Bacterial debris Matrix permreduction
Cement debrisand fluids
Mineral damageby fluids
Mineral Scales Turbulence athigh rates
Water influx,phase changes
Perfs – number,phasing, size,depth, cleanup
Emulsionsrelated to pH andgas use
Dew point andbubble point –relative perm.
Emulsions,foams, froths andsludges
Formationdisaggregation –sanding, fines
Limitedformation entry
Damage bypolymer &surfactant
Paraffin (wax)precipitation
Corrosion,erosion, andabrasion
Lift problemsfrom fluidchanges
Screen and G.P.restriction
Precipitates andsolids releasedby acids
Asphaltenes andTars
Deliquificationand lift
Subsidence
The Effect of Damage on Production
Rate = (DP x k x h) / (141.2 mo bo s)
Where:
DP = differential pressure (drawdown due to skin)DP = differential pressure (drawdown due to skin)
k = reservoir permeability, md
h = height of zone, ft
mo = viscosity, cp
bo = reservoir vol factor
s = skin factor
Root Causes of Residual Damage AfterClean-up Flow….
• High perm formations less affected?
– Major damage removers:
• Flow Rate per unit area,
• Flow Volume per unit area,• Flow Volume per unit area,
• Pressure pulse?
• Drawdown per unit area – a control?
First Problem
We don’t understand cleanup byflow…
It’s a matter of flow rate and volumethrough a given area.
For the same paythickness, a horizontalwell or a fractured wellmay contact 100’s oftimes more pay zone areathan a vertical well.
Clean-up flow is“diluted” by thelength of intervalopen at once forcleanout.
Now, think about the set drawdown – say500 psi - per unit area, the velocitygenerated and the total volume per area.
A 10 ft pay in avertical well w/ 6”diam. yields contactarea of 16 ft2
A 1000 ft pay in ahorizontal well w/ 6”diam. yields contactarea of 1600 ft2
Which has the potential of cleaningup faster and more completely?
Horiz. Well – assume 5x more than verticalflow (typical) – would generate 5000 bpd,but spread over 1600 ft2 – and release aclean-up flow of only 3 gal per hour per ft.
5000 bpd
Vertical well - 500 psidrawdown and an inflow of1000 bbl/day/ft spread outover just 16 ft2 will generate aclean-up flow of 110 gal perhour per ft.
clean-up flow of only 3 gal per hour per ft.The velocity may be too low to get goodcleanup.
1000 bpd
Second Problem
• We don’t understand damage.
– How it got there
– How it is removed.
– How to prevent it.– How to prevent it.
– What operations put the well’s productivity atrisk.
PI Change After Workover - Perfs Protected
20
30
40
50
%C
han
ge
inP
I
0.3 1.2 3.1 4.6 8.4
PI of wells
When perfs were protected, that was little risk of long term damage.
-40
-30
-20
-10
0
10
20
1 2 3 4 5 6 7 8 9 10 11
%C
han
ge
inP
I
Short Term PI Change
Long Term PI Change
SPE 26042
Damage in Fractured Wells with Unprotected
Perforations
-20
-10
0
1 2 3 4 5
%D
am
ag
e PIi = 7.55
When the perfs were not protected, the well was damaged.
-80
-70
-60
-50
-40
-30
%D
am
ag
e
PIi = 1.92
PIi = 6.21
PIi = 7.55
PIi = 7.55
PIi = 18.1
Effect of Scraping or Milling Adjacent to Open
Perforations
0
10
20 Perfs not protected by
LCM prior to scraping
One very detrimental action was running a scraper prior to packer setting. Thescraping and surging drives debris into unprotected perfs.
-60
-50
-40
-30
-20
-10
0
1 2
%C
ha
ng
ein
PI
Short Term PI Change
Long Term PI Change
Perfs protected by
LCM
SPE 26042
Kill Pills: Summary of Overall Effectiveness in
Non Fractured Wells
5
10
%C
han
ge
inP
I
Sized Borate Salts
(4)
Cellulose
Fibers (3) HEC Pills No Pills
Sized particulates, particularly those that can be removed, are much less damaging than mostpolymers.
-25
-20
-15
-10
-5
0
1 2 3 4 5 6 7
%C
han
ge
inP
I
Sized Sodium
Chloride (12)
No Near Perf Milling
(6)
Near Perf Milling or
Scraping (3)
No Near Perf
Milling (8)
SPE 26042
Near Perf Milling
or Scraping (10)
Third Problem
• We don’t know enough about timing of damageremoval.
– Variety of causes• Polymer dehydration
• Decomposition of materials• Decomposition of materials
• Adsorption, absorption and capillary effects
• Field data from Troika (100,000 md-ft) show initialflow improves PI, but later flow does not.
Note that PI remained improved, even after drawdown was reduced.
Effect of Drawdown on PI
Cleanup Lessons
• On initial cleanup, PI erratically increased asthe choke was opened. The typical responsewas a decrease, as if the well or part of theflow pathway were loading up, followed by asharp PI increase, seemingly when thesharp PI increase, seemingly when theobstruction was unloaded.
• Very little partially broken polymer wasrecovered, but the early load water recoverymatched the increase in PI.
Cleanup Lessons
• The wells cleaned up steadily with increasingdrawdown in the period of time immediatelyfollowing start of backflow. Cleanup wasincreasing, measured by increasing PI, at theend of the first short cleanup periods (shut-inend of the first short cleanup periods (shut-inof the well).
Cleanup Lessons
• After initiation of production operations (thiswas after the first cleanup flow), no furthercleanup of damage was seen, regardless ofdrawdown. The reason is not known, but maybe due to polymer adhering or cooking out??.be due to polymer adhering or cooking out??.
• Lower skins were linked to both sand flowbefore the completion was run (sand surgeremoved damage), increased cleanup flowvolumes (and drawdown) on the initial cleanup,and more effective frac stimulations.
Fourth Problem
• We don’t understand how damage impactseconomic return.
Example Economics - Skin Sensitivity
140
150
160
170
PV
-10,
$m
m
25
30
35
40
PV10
100
110
120
130
0 5 10 15 20 25
Skin
PV
-10,
$m
m
10
15
20
25ROR
Type ofDamage
MostProbableLocation
Impact onProductivityif notRemoved
SurgePressureNeeded forRemoval?
Flow Vol.Or TimeNeeded forRemoval?
RemovalHampered byLimits onCleanup Vol?
AlternateMethods ofRemoval orPrevention
Mud Cakein Pay Zone
FormationFace
Moderate toSevere
Yes SpurtVolume
Yes Acids, Soaps,Enzymes
Mud Filt. <12” Minor - mod. No No
Damage Removal
Whole MudLoss
Fracturesand largevugs
Severe Possible,Can help infew cases.
Depend onCond. fewcasessimilar
Yes, flowcombined withsolventtreatment
Few successfulwhole mudremovals whenvol. > 200 bbls.
CementFiltrate
<12” intopay
Only if claydamage
No No
PerforationCrush Zone
½” aroundperf
Moderate toSevere
Yes 4 to 12gal/perf
Yes Surge smallzones intochamber, acids,pulses, fracs
Formationsand inperfs
perftunnels
Most severe Cleanupand reperf
Depends oninitial &lateractions
Develop goodperf andprepack actions
Type of Damage Skin range CommentsMud Cake in PayZone
+5 to +300,+15 is typical
Mud skin is usually shallow and has more impact whenturbulence and non-darcy skin problems are most severe. Mudcake is usually by-passed by perforating.
Mud Filtrate +3 to +30 Filtrate usually recovered by steady flow and time. Related torelative perm effects. This is usually a short lived problem (1 to
Damage Effects
relative perm effects. This is usually a short lived problem (1 to3 weeks)
Whole Mud Loss (inpay zone)
>+50 Options depend on mud volume lost. Enzymes, solvents andacids for small volumes (<10 bbls). Sidetrack if over 1000 bbls.Low solids mud can be removed by concentrating on viscosifierdestruction or dispersment.
Cement Filtrate +10 to +20 Very shallow clay problems. Perforate with deep penetratingcharges to get beyond. Use leakoff control on cement.
Perforation CrushZone
+10 to +20 Perf small intervals underbalanced. Isolation packer breaksown,explosive sleeve breakdown (very simple) - must beaccomplished prior to gravel packing.
Formation sand inperfs
>+50 Most severe typical damage - cleanout and recompletionrequired
Mud Damage
• Common problems
– fines in the mud - physical plugging
– wetting of formation by mud surfactants
– emulsions– emulsions
– reactions with the formation fluids
– reaction with the formation clays
Oil based mud cleanup is a special case, requiringdispersal of the OBM emulsifying agents andwetting of the particles to prevent damage.Contact with acid, as shown in the following slides,will produce some severe sludges that are verydifficult to break.
A 50-50 mix of 14 ppg OBM and 15% HCl.The resultant sludge formed immediatelyand was stable for months.
Polymer Damage
• From: muds, pills, frac, carriers
• Stable? - for years
• location - depends on form polymer was in
– dispersed properly - surface to deep in formation– dispersed properly - surface to deep in formation
– in pills and mass - right in perfs
Particles in the Fluid
• Solids from tanks,lines and fluids
• Severe problem, butoften ignoredoften ignored
Particulate Damage
• Unintended particulates - “dirty fluids”– filter fluids to 5 microns at Beta of 1000
– maximum NTU of 30, preferable is 20
– clean tanks, lines - how about tubulars?– clean tanks, lines - how about tubulars?
• Particles in fluid loss pills– mixed in proper range for perm encountered?
– Will it come off formation? Can it come back thrupack? Thru screen? What about removal?
Horizontal Well Formation DamageTheories
Zone of Invasion - Heterogeneous Case
50423010
Stress on the Formation – three packersSwell packer, 50 psiexerted pressure,7.5 ft elementcontact length
Inflatable packer,2000 psi exerted
In the bottom twopackers, the forceexerted on theformation issufficient to createa fracture at least2000 psi exerted
pressure, 10 ftelement contactlength
Mechanical packer,6000 psi exertedpressure, 0.5 ftelement contactlength
a fracture at least12” deep withoutadded fluidpressure.These fractures mayfocus frac initiationduring a frac job.
SPE 123589
Model of Breakdown Pressure
SPE 123589
Modeled Stress around the Wellbore
The finite elementmodel of stress arounda horizontal well showsthe lowest stress at thetop of the wellbore.
Fracture initiation mayFracture initiation maybe easiest at the topand bottom of thewellbore unlessdisturbed by formationheterogeneities.
Inflatable Bridge Plug (IBP), orInflatable Casing Packer (ICP)?
• Inflatable plugs –Reliability Factors
• # times inflated in a run
• Maximum Inflation
• Element compositionand length
• Set Point
• Casing or OH?
• Inflatable Packers –Reliability Factors
• Slide Damage
• Set Point
• Casing or OH?
• Permeability of zone?
• Inflation Sequence
• Shrinkage?• Casing or OH?
• Permeability of zone?
• Shrinkage?
• Time?
Learning? – caliper the set point first!
After initial setting, inflatable plugsdo not come back to initial
diameters. Allow about a 20% ODincrease in clearance calculations.
Maximum Flex Point
Inflatables rely on expansion of an inner rubber bag that pushes steel cables or slatsagainst the wall of the pipe or the open hole. The only gripping ability is generated by thefriction of the steel against the pipe or open hole. This is critically dependent on theinflation pressure and the exterior slat or cable design. For a permanent seal, placeseveral bailers of cement on top of the inflatable.
Baker5/26/2010 301
George E. King EngineeringGEKEngineering.com
Damage from over inflation can bepermanent. Know the ID of the set
points.
How much differential well pressurecan an ICP hold?
Depends on the clearances, the expansion percentage, whatinflates the IBP, the permeability of the formation where it isset, the length, the fluids on the outside and the temperature– and that’s just for starters.
Failures on Running Plugs (RBPs) andPackers
• Failure Causes:
– Running the plug too fast (fluid viscosity dependent)
– Deposits on the tubular wall – wax, scale, corrosion
– Deformed or corroded tubing – caliper?
– One heavy wall joint in the midst of a string – caliper?
– Setting tool performance at this depth, deviation, temp?
– Pipe body too hard (slips won’t grip in V-150?)
– Pressure differential out of plug capacity
– Temperature beyond either initial or long termtemperature capacity (composite plugs break down).
Halliburton Energy ServicesGeneral Guidelines For SealsHalliburton Energy ServicesGeneral Guidelines For Seals
(1)
PEEK(2), (4) Ryton Fluorel(3) Aflas(3) Chemraz(3) Viton(3) Neoprene(3) Nitrile(3) Kalrez(3) Teflon(3)
Filled Unfilled Unfilled Filled Unfilled Filled Filled Filled Filled Unfilled
350 350 450 350 325 300 275 450 400 325
(177) (177) (232) (177) (163) (149) (135) (232) (204) (163)
Above Below
15,000 10,000 15,000 5000 5000 5000 3000 15,000 15,000 5000
(103) (68.9) (103) (34.4) (34.4) (34.4) (20.7) (103) (103) (34.4)
A A A A A B B NR NR A A A
A A B B A B B C A A A A
A A A A A A A B B A A A
(2), (4)Compound
Service °F
(°C)
Pressure psi
(MPa)
Environments
H2S
CO2
CH4 (Methane)
Hydrocarbons
(2), (4)
A-Satisfactory B - Little or no effect C - Swells D - Attacks NR - Not recommended NT - Not tested
NOTE: (1) This information provides general guidelines for the selection of seal materials and is provided for informational purposes only. Seal Specialists with Halliburton Energy Services should be consulted for the actual selection of sealsfor use in specific applications. Halliburton Energy Services will not be liable for any damage resulting from the use of this information without consultation with Halliburton Seal Specialists.
(2) Contact Technical Services at Halliburton Energy Services - Dallas for service temperature and pressure.
(3) Back-Up Rings must be used.
(4) There could be a slight variation in both temperature and pressure rating depending on specific equipment and seal designs.
A A A A A A A B C A A A A
A A A C A A A NR NR A A A
A A C B A C C B A A A A
A A A A A A A NR NR A A A
A A NR A A NR NR NR B A A A
A A A A A A A C A B A A
A A NR A A NR NR NR NR NR B B
Diesel A A A NR A A A B B A A A
Hydrocarbons
(Sweet Crude)
Xylene
Alcohols
Zinc Bromide
Inhibitors
Salt Water
Steam
5/26/2010 305
Temperatures in the Well? Circulating orHigh Rate Injection?
0
2000
4000
6000
30 40 50 60 70 80 90 100 110 120 130
Tubing
Tbg Fluid
Casing 1
Undisturbed
0
2000
4000
6000
30 40 50 60 70 80 90 100 110 120 130
Undisturbed
Tbg Fluid
Tubing
Casing 1
8000
10000
12000
14000
16000
18000
Circulation pump rate = 8-BPM
BHST= 122*F
BHCT= 98*F
8000
10000
12000
14000
16000
18000
Frac job pump rate = 35-BPM
BHST= 125*F
BHTT= 86*F
5/26/2010 306
Low Pressure Applications
Model AD-1
Tension Set
•Mechanical Jay
•Waterflood
Model G
Compression Set
•Mechanical Jay
•Low Pressure•Waterflood
•Disposal
•Shallow Production
•Emergency Shear
Release
•Low Pressure
Production
•Emergency
Rotational Release
RETRIEVABLE CASING PACKERMODEL “R-3” DOUBLE GRIP
• Double grip, compression set packerwith unloader
• Medium performance, generalservice packer
• J slot mechanism for setting andreleasingreleasing
• Hydraulic, button type holddown
• Bypass design speeds equalizationand resists swab-off
• Differential lock helps keep bypassvalve closed
Medium ServiceModel A-3 Lok-Set
•Double grip, compression setpacker
•Medium performance,
general service packer
•Sets with right hand rotation•Sets with right hand rotation
and slack-off weight
•Can be landed in compression,
neutral or tension
•Releases with right hand
rotation and up strain
Heavy Duty ServiceHeavy Duty ServiceModel Hornet HDModel Hornet HD
Double grip, compression or tension setpacker
Medium performance, to 10,000 psi @ 350Fgeneral service packer
Sets with ¼ turn right hand rotation andslack-off weight
Can be landed in compression,
neutral or tension
Releases with ¼ turn right hand rotation
Packer Performance Envelope
• Failure Modes
• Pressure Ratings
• Limitations
Packer Performance Envelope
SIZE 194 "SAB-3" 47 X 38 PACKERT
EN
SIL
E
9-5/8" 53.5# Csg (8.535 I.D.) - 4140, 18-22 Rc BODY & PISTON COVER, CAST IRON CONES
Graphical Presentation of Rated Performance Limits
Represents Effects of Combined Loading on Components
PRESSURE
FO
RC
E
0
0
ABOVE BELOW
TE
NS
ILE
SE
T-D
OW
N
Performance EnvelopePacker Performance Envelope Summary
Above Pressure Below
Tensio
n
1 2
3
4
FO
RC
E
Packer Failure Modes
(as represented ingraph)
1 Tensile failure of LH
square thread
2 Tensile failure atbody/guide thread
FO
RC
E
4
Com
pre
ssio
n
3 5
7 6
Above PRESSURE Below
3 Body collapse
4 Packing elementsystem failure
5 Pin collapse atbody/guide thread
6 Bearing failure at sealassembly
7 Body lock ring failure
Effects of Material SelectionT
EN
SIO
N
0
PERMANENT PACKER RATING ENVELOPE
With Standard Materials
With NACE Materials
SE
TD
OW
N
PRESSURE ABOVE PRESSURE BELOW0
18-22 Rc Body
& Cast Iron Cones30-36 Rc Body & Cones
Performance Envelope / Tube Move
•5-1/2" 26# Tbg
TUBING HANGER
•Tubing Affected Areas
Top Joint Tension
Packer To Tubing
•4-1/2" 18.8# Tbg
7-5/8" OD 33.7# Csg
KC-22 ANCHOR
PACKER
Perforations
•Annulus
Packer To Tubing
Force
Compressive Loads
Differential Pressures
Packer Failure Causes
• Body Collapse– ID of seal bore contacts OD of seal assembly
– Caused by differential pressure above or belowthe packer, or by packer and tubing forces; or by acombination of the two.combination of the two.
– Virtually all of the pressure and forces exerted onthe packer are locked in by the slip system. Thebody remains collapsed even after the forces areremoved.
5/26/2010 316George E. King Engineering
GEKEngineering.com
Packer Failure Causes
• Body Collapse (continued)
– Since pressures and forces are dependent on the cross-sectional area of the packing element, they are dependenton the casing ID.
– Each size packer is used in a range of casing ID’s (weights)– Each size packer is used in a range of casing ID’s (weights)
– As casing ID increases, the expansion of the packingelement mustbe greater - adverselyaffects packer rating.
5/26/2010 317George E. King Engineering
GEKEngineering.com
Consequences of Body Collapse
• Not a catastrophic failure (sealing notcompromised)
– often cannot remove seals from packer bore
– Safe Operating Region - 3 on envelope
5/26/2010 318George E. King Engineering
GEKEngineering.com
Packer Failure Causes
• Packing Element System Failure
– failure of the element occurs when the elementextrudes through the back-up system
5/26/2010 319George E. King Engineering
GEKEngineering.com
Packer Failure Causes
• Causes of packing element failure
– temperature of seal material exceeded
– excess pressure on element causes extrusion
– chemical attack (breakdown or softening)
– gas permeation and sudden decompression causingblisters and seal ruptures
– backup system failures
– seal bore corrosion or erosion leaves sealing surface rough
5/26/2010 320George E. King Engineering
GEKEngineering.com
Consequences of Seal Failure
• Catastrophic failure (sealing compromised)
– seal is lost - leaks may cause other problems
– often cannot remove seals from packer bore(baked, hardened, fused, etc.)(baked, hardened, fused, etc.)
– Safe Operating Region - 4 on envelope
5/26/2010 321George E. King Engineering
GEKEngineering.com
Packer Failure Causes
• Pin collapse at the body/guide connection
– like a body collapse, collapse of the pin connection at thelower connection with maximum deflection at the middelof the lower thread.
– Differential pressure can occur when the seals are in a seal– Differential pressure can occur when the seals are in a sealbore extension below packer or if a wireline plug is set in anipple in the tailpipe.
– Consequences - non-catastrophic
– Region - 5 on envelope
5/26/2010 322George E. King Engineering
GEKEngineering.com
Using The Packer Envelope in WellDesign
• Plot data from tubing movement and stressprograms on a packer envelope to determineif the loads fall in the safe area during initialsetting, production, stimulation and killsetting, production, stimulation and killoperations.
5/26/2010 323George E. King Engineering
GEKEngineering.com
Temperature Extremes
• The extremes of temperature change (higherthan normal) are usually seen in operationsinvolving cyclic thermal processes.
• Lower than normal temperatures may be seen• Lower than normal temperatures may be seenin permafrost, sea floor penetrating and CO2
operations.
5/26/2010 324
Setting the Packer
• Chances of setting packers go up sharply whena casing scraper is run. (Remember the burrson the perforations?)
• The quantity of debris turned loose from thecasing wall is often severe! (Tens of poundsworth!) Watch the formation damage.
5/26/2010 325
Packer Set Point Requirements
• Avoid setting packer in thesame joint where previouspackers have been set.
• Avoid doglegs, fault locationsor high earth stress zones
• Adequate cement and bondrequired behind pipe atpacker set point
• Remove burrs from pipeabove packer set point
• Remove debris (dope, millscale, mud, cement, etc.) oncasing wall (fills slip teeth)
• Well pressures are withinrange of packer at set pointpacker set point
• Caliper casing above andthrough the packer set point
• Clearance between packerand casing at set point iswithin rated range of packer
• Avoid zones of high corrosion,either internal or external.
range of packer at set point
• Pipe alloy compatible withsetting slips (hardness ofcasing relative to packer slips)
• Slip design & contact areaacceptable for slip holding
• Weight applied to packer canbe transferred to formation
5/26/2010 326
Information Required Before SettingPacker or Plug
• Wellbore drawing with all diameters
• Last TD tag – rerun?
• Doglegs and deviations
• Viscosity of fluid in wellbore– Calculate running speed vs. surge/swab.– Calculate running speed vs. surge/swab.
• Copy of reference logs
• Where have other packers been set (avoid that joint)
• Set point requirements
• How can it be equalized if it has to be pulled?
5/26/2010 327
Job Checks
• Measurements from CCL to a packer referencepoint.
• Run in hole at about 100 fpm, slowing at IDrestrictions.restrictions.
• Using CCL/GR, log up and correlate depths
• Set packer – look for line weight reduction
• Disconnect and log up a few collars (may beslightly off depth after disconnecting).
5/26/2010 328
Job Checks
• Drop back and gently tag packer with settingtool to confirm depth.
• Log back up a few collars.
5/26/2010 329
Packer Setting Guidelines
• Drift
• Scraping
• Casing Support
5/26/2010 330
Drift the Casing
• Casing ID requirements above the set point
• Casing ID requirements below the set point
• Check the drift to deepest point with drift ofdiameter and length of packer.diameter and length of packer.
5/26/2010 331
Clean/Scrape The Casing?
• Removal of perforation burrs minimizes elastomerseal damage
• Removal of cement, mud, pipe dope and mill scaleminimize debris that can fill the slips.
• Scraping casing can increase packer setting success• Scraping casing can increase packer setting success
• Scraping casing can also produce some severeformation damage if perforations are not protected.
5/26/2010 332
Casing Scraper – Designed to knock offperforation burrs, lips in tubing pins,cement and mud sheaths, scale, etc.
It cleans the pipe before setting apacker or plug.
The debris it turns loose from the pipemay damage the formation unless thepay is protected by a LCM or plug.
5/26/2010 333
Effect of Scraping or Milling Adjacent to Open
Perforations
0
10
20 Perfs not protected by
LCM prior to scraping
One very detrimental action was running a scraper prior to packer setting. Thescraping and surging drives debris into unprotected perfs.
-60
-50
-40
-30
-20
-10
0
1 2
%C
ha
ng
ein
PI
Short Term PI Change
Long Term PI Change
Perfs protected by
LCM
SPE 26042
5/26/2010 334
Lift Systems
• Optimizing the lift system is generally one ofthe most economic well operations.
ESP – Root Failure Cause Considerations
1. Collect data from first few weeks afterinstallation and from last few weeks beforefailures.
a. Initial production data verifies design informationa. Initial production data verifies design information
b. Data before failure show changes in wellperformance or pump wear.
2. Maximum run times can only be achieved if theRoot Cause of Failure is identified.
SPE 68789
ESP Typical Run Times
• Extremely wide variance– Short times 50 to 100 days – where pumps handle
high gas content, solids or very hot wells in smallcasing
– Medium times – 600 to 800 days – where user– Medium times – 600 to 800 days – where userand supplier pull pumps at first sign of problemsand examine.
– Longest run times – 10 years plus – idealconditions (low temperature, low GOR, high fluidlevels, instrumented completions)
Run Times - Optimizing
Increasing Run Time -
Specific Need Data
• Tubing and casing pressure
• Pumped fluid volume
• Fluid composition
• Presence, amount, size and type of solids• Presence, amount, size and type of solids
• Drive output volts
• Amps
• Operating speed
• Fluid level, BHP, BHT
Review the root cause failure fortrends between wells.
– Power fluctuations
– Type of installations
– Water and oil types – compatibility with rubber
– Solids
– Gas content
– Temperatures– Temperatures
– Service technician
– Pump supplier
– Shroud type and design – cooling
– Casing size and clearances
– Pump setting location
• For a “complete” list of failures and repair solutions – see SPE68789 by Jim Lea and Mike Wells.
Review the Previous ESP Pull History
• Example – motor burnout resulting from insulationfatigue from overheating due to a plugged pump.
• Set points in deviated sections have very high failuresdue to bearing and shaft wear.due to bearing and shaft wear.------------------------------------------------------------
• Calculated well production from field data can bemisleading – accuracy is often poor.
• Get accurate production data.
Unusual problems
• Gassy wells – under-load (UL) settings werenot correct – did not allow pump shutdownwhen the pump became gas locked.
• Oversized motor in hot or low flow wells –• Oversized motor in hot or low flow wells –current draw was like idle load and UL did nottrip.
ESP Gas Lock Description
• “At the low intake pressures the density difference between theliquid and the gas phase can approach three orders of magnitude.The viscosity difference can be two to three orders of magnitude.The two fluids, when subjected to the forces in a centrifugalpump, can flow at different rates and sometimes in oppositedirections. The impeller accelerates the fluid and centrifugal forcedirections. The impeller accelerates the fluid and centrifugal forcemoves the fluids to the peripheral exit. The magnitude of theforce is related to the impeller rotational rate, the radial locationof the particle of fluid and its density. The gas, being less dense, isforced to the low side of the impeller vane. The gas begins toexpand, surge and start separating the liquid from the leadingedge of the vane, blocking the passage.”
B.L. Wilson, SPE Gulf Coast ESP Workshop, April 1998.
Failure Rates and Predictions
• Mostly mechanical
• The actual rates vary widely with conditionsand company
Deep Water Production - 2004
shallow casingfailure/ pressure
6%TRSCSSV & Inserts
14%
Flux11%
DWP Historical Well Failure Mechanism
Foot valve3%
Leaks packer & tbg6%
Horz. OH sandcontol failures
17%
Damaged OH screen3%
Compaction8%
sand control infantmortality/ design
6%
Sand control failureunclassified
26%
Failure Rate Variation Reflects CompaniesExpertise, age of wells & Area of Operation
Company Device Failure Rate1
failures/well/yrArea of Operations
Company A (wet tree) ScSSVs 0.011 GOM
Company B (wet tree) ScSSVs 0.002 GOM
Company C (dry & wet) ScSSVs 0.004 North Sea
Industry Overall (dry & wet) ScSSVs 0.1052 GOMIndustry Overall (dry & wet) ScSSVs 0.1052 GOM
1. About 60% of the ScSSV failures involve control line crushing, connectionproblem or plugging. More problems are noted at higher well pressures and inareas of flow assurance problems.
2. Reflects older wells in the shelf where ScSSV failure & malfunction is common3. Intervention rate is sharply lower on wet tree wells than dry tree wells.
Failure Rates for Dry Tree Well Components
Equipment TotalWells
Failure Ratefailure-per-well-per-year
Tubing 209 0.0083
Packer 209 0.0024
SSSV failures 209 0.0071
SSSV malfunctions 209 0.0047SSSV malfunctions 209 0.0047
Control Lines (crush, leak, plug) 209 0.0091
Well Head (Dry) 209 0.0005
Well Head Valve 209 0.0024
Choke 209 0.0024
Cement Lap Failure 209 0.0095
Other Failure 209 0.0047
Failure Rates for Wet Tree Well Components
Equipment TotalWells
Failure Ratefailure-per-well-per-year
Wet Tree Failure 72 0
Wet Tree Seal Failure 72 0.017
Wet Tree Pod Failure 72 0.023
Wet Tree Valve Failure 72 0.048Wet Tree Valve Failure 72 0.048
Wet Tree Choke Failure 72 0.005
ScSSV Failure 72 0.014
ScSSV Incidents 72 0.024
Flow Assurance Issues 72 0.01 to 0.15
Sand Control Failures 94 0.013
Sand Control Failures (circa 2004, SPE 84262)CompletionType
#Wells
TtlYrs
DesignFail, %
ApplicationFail, %
EarlyFail, %
Prod.Fail, %
Prod.Fail,f/w/y
SubsiFail,f/w/y
IntervenRatei/w/y
Injectors 30 85 0 10 0 31.3 0.070 0 0.059
ScreenlessFracs
26 107 0 27 0 7.7 0.019 0 0.808
Cased &Perf
61 336 0 1.6 0 41 0.074 0.003 0.024
Screen Only 194 756 0.5 0 1 21.6 0.056 0.0013 0.019Screen Only 194 756 0.5 0 1 21.6 0.056 0.0013 0.019
Expandable 197* 262 0.5 3.6* 0.5 3 0.023*
CHGP 387 1664 0 2.3 0.8 5.2 0.012 0.0006 0
OHGP 208* 613 0 7.7* 0.5 4.8 0.016* 0.0016 0.021
HRWP 187 556 0 0.5 0.5 2.7 0.009 0 0.002
Frac Pack 842 3351 1.5 2.4 0.2 2 0.005 0.0015 0.001
Total Wells 2132 7538
* Expandable screen and OHGPs were in early time at this point – better results now.
Producer Injector
Interventionfreq i/w/y
Interventionfreq in i/w/y Source and Comments
Root Failure major minor major minorSand control completion -stand alone screen
0.056 0.08 0.1 0 BP's 2000 well Sand Control FailuresDatabase (SPE 84262)
Sand control completion -gravel pack completion
0.011 0.025 0.05 0 BP's 2000 well Sand Control FailuresDatabase (SPE 84262)
Sand control completion -frac pack completion
0.005 0.007 BP's 2000 well Sand Control FailuresDatabase (SPE 84262)
Liner hanger 0.01 0.015 Data on hanger failures in GOM andlower 48 US
Intervention Rates – Land Wells(US & Canada, 2000 to 2004)
lower 48 USTubing, sweet gas, nonchrome, >7 psi CO2 partialpressure
0.2 0.05
General reliability data GoM and USOnshore
Tubing, sweet gas, nonchrome, >5<7 psi CO2 partialpressure
0.17 0.05
General reliability data GoM and USOnshore
Tubing, sweet gas, nonchrome, <5 psi CO2 partialpressure
0.1 0.05
General reliability data GoM and USOnshore
Tubing, Chrome13, CO2partial pressure <7
0.01
Tubing, water injector,chrome
0.3 0.1 General Reliability, Comments byCorrosion Group on injectors
Tubing, water injector, non-chrome
0.1 0.05 General Reliability, Comments byCorrosion Group on injectors
Producer InjectorInterventionfreq i/w/y
Interventionfreq in i/w/y Source and Comments
TT Patch / Repair 0.005 to 0.01 Estimate based on Alaskarepairs
Setting Plugs 0.1 Observed problems fromAlaska and Lower 48 USA,North Sea study on settingplugs.
Problems Encountered During Specific Operations, circa2000-2004
plugs.Tailpipe 0.02 0.02 Estimate from observations of
plug sticking and corrosionproblems.
Packer 0.0024 0.01 0.0024 0.005 Data from vendors (Baker)and direct experience andanalysis of failed packers inAlgeria and US.
PBR or similar 0.07 0.02 0.07 0.02 Stuck seal data fromHalliburton (Tom Rey) andstinger retrieval data fromfishing book.
Gas Lift - Land Wellscirca 1995-2004
Interventionfreq i/w/y Source and Comments
Gas lift failures 0.01Data from Weatherford (Rick Seagraves),modified, and BP Alaska
Gas Lift Optimization 0.08Data from Weatherford (Rick Seagraves),modified, and BP Alaska
Chemical Inj Mandrel 0.01Data from Weatherford (Rick Seagraves),modified
Chem Inj Valve 0.05Data from Weatherford (Rick Seagraves),modified
North Sea Well Event(Intervention)
% ofTime
InterventionFrequencyfailures/well/yr
InterventionFrequencyfailures/well/yr
InterventionFrequencyfailures/well/yr
Tubing RetrievableSSSV 20% 0.067 0.067Gas Lift Optimization 30% 0.1Gas Lift Equipment
North Sea Well Intervention Datacirca 2000
Gas Lift EquipmentFailures 3% 0.01Screens 15% 0.05Recompletions 12% 0.03Tubing Leaks 6% 0.01 0.045 0.011Stimulation 6% 0.01Logging 4% 0.01 0.05Seal Failures 3% 0.01 0.01 0.01Fishing 1% 0.03 0.03Sanding Up 0.06 0.025Profile Modification 0.01
Perf Condition ApproximateOpen
Perforations
References
Overbalance in Mud – moderate pressure well,no surge afterward
20% Downhole camera pictures, general well behaviorof Mobile bay and Opon well perforating
Overbalance in Mud – high pressure well, surgeand flow after perforating
30% SPE 16894
Overbalance in brine – no surge 35% SPE 15816
Overbalance in brine, surged 40% 15816, 16212
Overbalanced in acid, surge or no surge 45% Amoco Canadian Experiments
Perforating PerformanceCirca 1980 to 2004
Overbalanced in acid, surge or no surge 45% Amoco Canadian Experiments
Extreme Overbalanced Perforating, k<1 md, P>1.4 psi/ft with pumping after firing
60% Marathon Experiments and TerraTek tests(Dees, et.al.)
Extreme Overbalanced Perforating, k>1 md, P>1.4 psi/ft with no pumping
45% Amoco Canada experiments, Arco experiments
Underbalanced perfs, no flow 40% Downhole camera work, 14321, 16212,
Underbalanced perf, surge and flow >4 gal/perf,k>1md, h<50ft
50% 14,321, 16212, GOM experience (Bonomo andYoung’s Amoco work)
Underbalanced perf, surge and flow >4 gal/perf,k>1md, h>50ft
40% Anschutz Ranch Experience, 14321, 16212,
Underbalanced perf, surged and washed 75% 16212, Bonomo and Young’s Amoco work
Sand Abrasive Methods 80% 55044, downhole camera work from Canada
Bullet perforating, brittle formations such ascoal – some water wells
45% Coal well work, Mounds experiments (Amoco),Water well performance data
Bullet perforating, all other formations 25% Downhole camera work, well performance data
Activity % failure onfirst run
% failure onsecond run
Comments
Cement Packerplacement bybullheading
50% 25% Problems with contaminationand leaks
18
Cement Packerplacement by CT
10 to 15% 5%
Various Intervention SuccessCirca 1991 - 2005
placement by CTDual Hydraulic PackerRecovery
15 to 50%
Acidizing, matrix 30% to 70% historical results fromIndustry survey by Arco, 1991.Carl Montgomery
Wax Removal 20% to 60% Statistical survey ofmechanical and chemicalremoval techniques applieddownhole.
Scale Removal 10% to 30% Heavily dependent on removalmethod, mechanical, jettingand chemical methods varywith application.
Est. Int. Operation Success Rate Percent success on the first run or attempt.1981-85 1986-90 1991-95 1996-00 2001- Source
One Trip GP Systems 50% 72% 82%Robert Stomp, Conoco, IPQC Best Prac Sand Control,July 30/31, 2002
TCP - less than 200 ft 70% 92%M. Cloud and R. Kirkpatrick, Amoco, Internal report,1988
E-Line Perforating 98%Marathon Explosive Safety Conference, January20/21 2002
Tubing Cutoff - tension pulled, tool>/= 80% tubing ID 75% Amoco Study of Tubing Cut-Off SuccessTubing Cutoff - tension not pulled, or
Estimate of Initial Operations Success RateCirca 1981 to 2006
Tubing Cutoff - tension not pulled, ortool < 80% of tubing ID. 25% Amoco Study of Tubing Cut-Off Success
Fracturing (Hard Rock) 90% 92% Failure Frequency Data Base, BP led effort,
Frac and Pack 91% 95% Failure Frequency Data Base, BP led effort,
Frac and Pack - TSO 80% approximation
Gravel Pack - cased hole 97% Failure Frequency Data Base, BP led effort,
Gravel Pack - open hole 91% Failure Frequency Data Base, BP led effort,
High Rate Water Pack 99% Failure Frequency Data Base, BP led effort,
Expandable Sand Screens 86% Failure Frequency Data Base, BP led effort,
Screen Only Completions 98% Failure Frequency Data Base, BP led effort,
Perm Pkr Setting - scraper used 95% Dual Well Completion Operation Report
Perm Pkr Setting - scraper not used 85% Dual Well Completion Operation Report
ScSSV, succcess init run & test 98% Failure Frequency Data Base, BP led effort,
Acidizing, general use 30% Carl Montgomery, CEA study, 1995
All Coiled Tubing ops independent ofnumber of runs, non train wrecks 98% Nowsco North Sea StudyCoiled Tubing ops, no problemsrequiring NPT 75%
Activity % failure onfirst run
% failure onsecond run
Comments
WL run to EOT in 2-3/8”tubing
14% improve if cool water circulated4
WL run to EOT in largertubing
<2%
WL Plug setting 5% Assumes low scale, low paraffin environment
WL Plug pulling 20% 15% Debris over plug is major problem
Problems Encountered During Wirelineand CT Operations
WL Plug pulling 20% 15% Debris over plug is major problem
CT Plug Setting 10 to 15% Problems in sensitivity and depth control
CT plug pulling 10 to 15%
WL Perforating 2%to 3% <1% detonator/conductivity problems, assumes tubing isopen to TD
32
CT Perforating 5% to 8% 3% detonator/gun-to-gun failure, assumes tubing is open toTD
32
Tubing Puncher Charge 5% Depends on magnetic decentralizer operation33
Tube cut off, below packer 75% 75% Incomplete cut without tension29
Tube cut off, above packer 20% 20% Insufficient overpull, coatings & heavy or alloy pipe29,30
Sliding Sleeve Operation 10 to 50% depends on age, corrosion and debris, improve with CTimpact tool on CT
Problem in a Dual Incidence of failure(% of wells or units
over well life)
Comments and References.
Communicationbetween strings, nosliding sleeve
1 to 10% Lower figure reflects optimum seal selectionand good design of tubular and wellhead
4
connections, increases with sourenvironment
Dual Completions Failures
environment
Communicationbetween strings, slidingsleeve present
10 to 50% Lower figure reflects low debrisenvironment, increases with sourenvironment or debris
4
Dual Packer Failure 7% to15% Various factors including unseating due tocool fluids and leaks of the elements
42,43
Expansion Joint Failure to 50% Leaks42
Blowout, risk of 1blowout in 20 year welllife (side/side dual)
0.0023 Assumes a gas lifted completion21
Blowout, risk of 1pressure controlincident in 20 year welllife, concentric
0.0032 Assumes a gas lifted completion21
Difference Between Failure Rate andActual Intervention Rate - Trinidad Wells
Teak 70’s# wells
Teak70’swell-yr
Teak70’sF.R.
Early FailRate (%)
Teak 80’swells
Teak 80’swell-yr
Teak80’sF.R.
Early FailRate (%)
Teak90’swells
Teak 90’swell-yrs
Teak90’s F.R.
Early FailRate (%)
Avg Sand Control FailRate (f/w/y)
55 134.3 0.28 16 19 86.6 0.08 11 8 17.2 0.12 25
Avg Sand Cntrl InterRate (i/w/y)
55 134.3 0.17 19 86.6 0.03 8 17.2 0.06
No Cntrl Failures -deep zones) f/w/y
15 41.3 0.15 7 6 19.6 0.05 17 2 5.9 0.17 50
No cntrl Interv (i/w/y) 15 41.3 0.02 6 19.6 0.05 2 5.9 0.17
Bare Screen Failuresf/w/y
7 17.6 0.28 14
Bare Screen Interv.i/w/y
7 17.6 0.23
CH GP Failures f/w/y 31 71.2 0.35 23 13 67 0.09 8 2 5.9 0.11 17
CH GP Interv. i/w/y 31 71.2 0.24 13 67 0.07 2 5.9 0
OH GP Failures f/w/y 2 4.3 0.47
OH GP Interv. i/w/y 2 4.3 0.24
Producer Injector
platform subsea platform subsea
Root Cause major minor major minor major minor major minor
Downhole sand control failure 0.1002 0 0.1002 0 0.0200 0 0.0200 0
Liner hanger / packer 0 0 0 0 0 0 0 0
Isolation devices 0 0.0021 0 0.0021 0 0.0021 0 0.0021
Tailpipe 0 0.0021 0 0.0021 0 0.0021 0 0.0021
Packer 0.0021 0 0.0021 0 0.0021 0 0.0021 0
PBR or similar 0 0 0 0 0 0 0 0
Tubing 0.0025 0 0.0025 0 0.0025 0 0.0025 0
Gas lift mandrel 0.0140 0.0140 0.0104 0.0104 0 0 0 0
DHPG 0 0 0 0 0 0 0 0
Chemical Injection Mandrel 0 0 0 0 0 0 0 0
DHSV 0.0173 0.0380 0.0173 0.0380 0.0035 0.0243 0.0035 0.0243
Tubing hanger 0.0033 0 0.0033 0 0.0033 0 0.0033 0
Bullhead Scale Squeezes 0 0.0113 0 0 0 0 0 0
Coiled Tubing Scale Squeezes 0 0.0873 0 0.0397 0 0 0 0
Scale Sidetracks 0.0086 0 0.0039 0 0 0 0 0
Scale Milling 0 0.0366 0 0.0166 0 0 0 0
Example of a WellIntervention Predictionin West AfricaDevelopment
Scale Milling 0 0.0366 0 0.0166 0 0 0 0
Wax 0 0.0021 0 0.0021 0 0 0 0
Hydrates 0 0.0056 0 0.0056 0 0 0 0
Asphaltenes 0 0 0 0 0 0 0 0
Sand clean-out 0 0.0042 0 0.0042 0 0.0042 0 0.0042
Production logging 0 0.1013 0 0.0193 0 0.1013 0 0.0486
Downhole fluid samples 0 0 0 0 0 0 0 0
Downhole memory gauges 0 0.0050 0 0 0 0 0 0
Downhole plugs 0 0 0 0 0 0 0 0
Reperforation 0 0 0 0 0 0 0 0
Water shut-off 0 0.0186 0 0.0186 0 0 0 0
Gas shut-off 0 0.0032 0 0.0032 0 0 0 0
Recomplete 0 0 0 0 0 0 0 0
Sidetrack 0.0085 0 0.0085 0 0.0085 0 0.0085 0
Stimulation / fracturing 0 0.0186 0 0.0186 0 0 0 0
Production / injection monitoring 0 0 0 0 0 0 0 0
Well integrity 0 0 0 0 0 0 0 0
X-mas tree 0 0 0.0152 0.0152 0 0 0.0139 0.0069
Controls 0 0 0 0.0214 0 0 0 0.0214
Flowline / pipeline 0 0 0 0.0145 0 0 0 0.0104
Subtotal 0.1565 0.3500 0.1634 0.2316 0.0399 0.1340 0.0538 0.1200
Total 0.5065 0.3950 0.1739 0.1738
Average WOW% by Vessel Type
Comparison of WOW Percentages by Vessel Type (NNS, 'M' Task Limit)
50.0%
60.0%
70.0%
DP Vessel
MODU
0.0%
10.0%
20.0%
30.0%
40.0%
jan feb mar apr may jun jul aug sep oct nov dec
Month
WO
W%
25Frank Ketelaars, Jardine &
Associates Ltd., Oct 19, 2000
Base Case Results – DP Vessel UtilisationDPVessel UtilisationBreakdown
Gas Lift Valve
5.2%Transit/Mob
12.9%
Zonal Isolatio
19.0%
ScaleRemoval
4.4%
SandRemoval
2.6%
Lower Completi
8.7%Reperforation
0.9%
ScaleSqueeze
12.2%
SCSSV
4.0%Well Logging
10.0%
Xmas Tree
3.8%
Stimulation
7.2%
Upper Completi
9.0%
AverageDPutilisationover 2000-2007periodis71daysper annum
6Frank Ketelaars, Jardine &
Associates Ltd., Oct 19, 2000
Definitions (pt 1)
• Intervention frequency – based ininterventions per well per year.
Total number of workoversTotal number of workoversfreq = ----------------------------------------------
(total well number) x (cum years operation)
Definitions (pt 2)
• Major intervention – requires a rig and killing well
• Minor intervention – wireline or CT, well not typ.killed (some include data gathering, some don’t) –data gathering not included in this report.data gathering not included in this report.
• Early failure – problem corrected while the rig is onthe well – not really a intervention frequencyconcern, but failure to repair make it a concern.
Value of Early Data?
• Not much value for early interventionfrequency numbers.
• Early data on subsea wells dominated byprototype and first series equipmentprototype and first series equipment
– Steep learning curve (design, installation,operation)
– Numerous failures
Intervention Frequency Variables
• Initial clean-up effectiveness*• Effectiveness of initial T.S.O. fracturing*• Equipment test tolerance• Dry or wet tree• How much damage will you put up with?• How much damage will you put up with?• Facility/Injectors at capacity?• Is data collection an intervention?
* Assumes the early problems were not corrected –effect on intervention frequency can be severe.
Intervention Frequency Ranges
• Clean-up effectiveness – 0.025 to 0.17• T.S.O. fracturing success – 0.1 to 0.4• Equipment test tolerance - 0.026 to 0.23• Wet or dry tree – 0.075 (wet) to 0.15 (dry)*• Wet or dry tree – 0.075 (wet) to 0.15 (dry)*• Tolerance for damage? 0.0 to 0.09+• Facility at capacity? – 0.0 to 0.09
* Dry tree interventions easier and lower risk. Drytree reserve recovery is 1.5 to 2.5 x that of wettree.
25%
65%
40%
60%
80%
Norwegian Study of Reserve Recovery vs. Tree
Location
Data from Gulfax and Statfiord Fields in Norwegian North Sea, data provided by Statoil
0%
20%
40%
Wet Tree Dry Tree
Recovery
Intervention Causes
• Pod Failures - 20 to 30% of total
• Flow assurance problems - 20% to 30%
• Subsurface safety valves -10 to 20%
• Profile modification – 10 to 15%• Profile modification – 10 to 15%
• Seal problems -10% to 15%
• Sand control failures -5% to 10%
Intervention Frequency in GOM
• Discount early data (e.g. Mars – 0.33 at onetime, Uropa: 0.4 (?) due to hydrates)
• Troika: 0.086 wells/year, but could be 0.26 iftwo wells with early failure problems aretwo wells with early failure problems areworked over soon.
• Pompano: 0.027 wells/year, excellent, butmuch lower rate wells than Troika
Well#
CumProd.,MM Bbls
Months onProduction
No. ofInterventions
ProdRate,M Bpd
Anglethrupay
MechSkin
GlobalSkin
TA1 10.29 32.5 0 7.5 <20o +216*
+502*
TA2 16.82 29.4 0 12 <20o +116*
+243*
Troika Data
*
TA3 31.95 33.9 0 28 <20o +64 N/A
TA4 18.4 17.9 1 30 <20o +50 N/A
TA5 28.3 26.3 0 29.2 54o +45.8 +92
GOM DW Intervention FrequencyNumbers ????
• Pod Failures (minor) – 0.05 to 0.33
• Flow assurance problems – 0.01 to 0.15
• Subsurface safety valves – 0.027 to 0.1
• Profile control - 0.025 to 0.1• Profile control - 0.025 to 0.1
• Seal problems (minor?) – 0.05 to ?
• Sand control failures (TSO)– 0.085 to 0.12
• Corrosion – 0.01 to 0.04
Intervention Comments
• Intervention Frequency Lowered by:
– Good cleanup (UB perf and flow)
– Effective stimulation (TSO event = capacity)
– No tolerance test program during installation– No tolerance test program during installation
– Low damage/high productivity as only completionbenchmark (forget rig time !!!!)
– Redundancies in operating system
– Flexibility in design
Summary Comments
• Intervention Frequency Raised by:
– No surge cleanup (OB perf and no flow)
– Slurry packing (no TSO event = low capacity)
– Less than perfect installation– Less than perfect installation
– Efforts to cut rig time
– Prototype and first edition equipment
– Non flexible designs
Intelligent Completions???
• Downhole gauges – great!
• Zone control by downhole valves? – expectfailures early (leak paths), but these may payout for control – it is a gamble.out for control – it is a gamble.
• Most reliable completions are big, dumb(simple) completions with flexibility for repairand recompletions.
Risks
• Low well numbers
• Injector/producer communication? In faulted & layeredreservoirs, expectation is an extreme risk.
• GOM DW plans do not include artificial lift. Most experienceddeep water operating company, Petrobras, studying threedeep water operating company, Petrobras, studying threeforms of DW lift.
• Upper completion design configurations should be flexible.This should include annulus pressure and temperaturemonitoring, annular venting capability and redundancies.
Tubing Pressure Testing:Why it was stopped at BP.
• There have been NO tubing leaks of premium threadsdiscovered after over 180 tubing tests performed on 60completions in the North Sea since the early 1990’s.
• Operations to support pressure testing of tubingaccount for 25% of completion time in pressure testing,account for 25% of completion time in pressure testing,running and pulling plugs, and special packer testing.
• At this high proportion of completion time, tubingtesting would have to find at least one tubing leakevery four completions to be cost effective.
• This project reviewed over 587000 feet of mild steeland chrome tubing with over 19500 connections.
Dan Gibson, 1998
Well Interventions – Planning Methodology
Tubing
retrievable
SSSV's
FishRecompletions
Logging
Gas Lift valves
(inc. back check
repair)Sealing
devices
Screens
Tubing
Stimulation
PER WELL FAILURE FREQUENCY ANALYSIS
Production Tree Water injectiontree
Gas DisposalWell
Cause of intervention Classed
'Intervention'
Classed
'Workover'
Classed
'Intervention'
Classed 'Workover' Classed
'Intervention'
Classed
'Workover'
Failure rate Failure rate Failure rate Failure rate Failure rate Failure rate
[ / in-service year] [ / in-service
year]
[ / in-service year] [ / in-service year] [ / in-service year] [ / in-service
year]
Subsea X-mas tree 0.052 0.038 0.035
Well Interventions – Planning Methodology
• Schiehallion Well Intervention Frequency Predictions (D Driesen 1997) basedon SINTEF WellmasterTM Database…
Subsea X-mas tree
Failure
0.052 0.038 0.035
Tubing Failure 0.00215 0.00215
DHSV Failure 0.05 0.05 0.05
Gaslift System Failure 0.006
Elastomeric Seal Failure
Sandcontrol System
Failure
0.0198 0.015
Consequential Failure 0 0.003 0 0.003 0 0.003
Reservoir Surveillance 0.02274 0.017145 0.0195 0.012945 0.015 0.0114
Dynamic Data Aquisition:
Before Year 2000 0.007
After the year 2000 0
Water Shut-off @
receiver:
Before the year 2000 0
After the Year 2000 0.007
Water Shut-off @ source:
Before the year 2000 0
After the Year 2000 0.019
Gas Shut-off 0
Side track/re-completions 0.0132 0.01
Stimulation 0 0
TOTAL = 0.0898 0.07035 0.084 0.05315 0.05 0.038
Well Interventions – Field A: Actual vs. Prediction
Why are there fewerinterventions and why isthe timing different?
Well Interventions – Field B Actual vs. Prediction
Why are there fewerinterventions and why isthe timing different?
Losses – What?
What was the problem?
Subsea Field A – impact of failures
• Up to 2003, field will be gas constrained, hence inthe event of production failure, some oil can berecovered by compensation (25%-50%).
• From 2004 field produces flat out: no compensationpossible.possible.
• Immediate water injection losses are only caused byW11 & W13 failures, 4.5 and 12 Mbbls/dayrespectively in 2000 production rates.
• Field has back-up gas disposal well, allowing partialproduction during failure. Oil loss varies from 43%loss in 2000 to no impact in 2007.
10
Field B – impact of failures
• Up to 2004, field is gas constrained; if prod failure,some oil rec by compensation (25%-50%).
• From 2005 field produces flat out: no comp
• Water injection is constrained by injection pumps,hence any reduction in water injection during WIhence any reduction in water injection during WIwell failure will result in production loss: Oil lossvaries from 8 Mbbls/d/injector to 2 Mbbls/d/injector
• In the event of gas disposal well failure, oilproduction can be maintained at 30Mbbls/d byutilizing gas for fuel; allowing minimum flare.
11
Platform Field – impact of failures
• During first three years, back-up wells on platformcan compensate for outage of one gas producer.
• After 2002 no compensation is available in winter.• After 2002 no compensation is available in winter.
• No losses are anticipated during low offtakeperiod
12
Questions?
1. Hashim, T.R., Khalid, M.Z., Kruit, W., Short, D., Duncan, B, Pauzi, N, Haron, J., Low, F.N.: “Implementation of Twin Well Technology Offshore Sarawak,” SPE 50082, SPE Asia Pacific Oil and Gas Conference and Exhibition, Perth, Australia, 12-14 October, 1998.
2. Mayol, J.R., Salazar, A.: ”Dual Completions in El Furrial Field,” SPE 23684, Second Latin American Pet. Eng. Conf., Caracas, March 8-11, 1992.
3. Gabert, R.F., Ghnelm, G. J.: ”Procedures and Practices of Dual-Completion Design in Abu Dhabi,” SPE Production Engineering, February 1991, p20.
4. El Hanbouly, H.S., Saqqa, M.R., Constantini, N.M.,: ”Problems Associated with Dual Completions in SIP Wells: A Case History,” SPE 17985, SPE Mid East Oil Technical Conference and Exhibition, Manama, Bahrain, 11-14 March, 1989
5. Webster, K.R., O’Brien, T.B.:”Deep Duals Simplified,” SPE 3904, Deep Drilling Symposium, Amarillo, Sept 12, 1972.
6. Moring, J.D.: “How Skelly Handles Deep Duals at Warwick,” Pet. Eng., Dec 1974, P66.
7. Austingard, A., Erichsen, L., Vikra, S.: ”Case History: Gullfaks C-36AT3, A Multipurpose Oil Production/Gas Injection Well in the North Sea,” SPE 49107, New Orleans, 27-30 Sep 1998.
8. Wilson, D.J., Barrilleaux, M.F.: ”Completion Design and Operational Considerations for Multizone Gravel Packs in Deep, High Angle Wells,” OTC 6751, Houston, May 6-9, 1991.
9. Hall, D., Gardes, R.: ”Downhole Splitter in the Gulf of Mexico: Field Introduction and Results,” OTC 7905, Houston, 1-4 May 1995.
10. Durham, K.S.: ”Tubing Movement, Forces, and Stresses in Dual-Flow Assembly Installations,” SPE 9265, SPEJ, December 1982, p866.
11. Lambie, D.A., Walton, B.: ”Gas Lift in Multiple Completed Wells,” Southwestern Petroleum Short Course, Lubbock, Tx., April 18-19, 1968.
12. Weatherford Enterra Gas Lift and Design Seminar, Aug 30-Sept 2, 1999.
13. Plathey, Granger, J.L., Agam, A.R., Arnaud, F.: ”Dual Gas Lift Experience in Handil Field D.”Proceedings of the 17 th Annual Convention, Jakarta, October 27, 1988.
14. Davis, J.B., Brown, K. E.: ”Attacking those Troublesome Dual Gas Lift Installations,” SPE 4067, San Antonio, Oct. 8-11, 1972.
15. Telfer, G.: ”Downhole Packers for Use with ESP Completions,” OTC 7066, May 4-7, 1972.
16. Tunstall, K.N.: ”Artifical Lift as Applied to the Multiple Completion Choke Assembly,” Southwestern Petroleum Short Course, April 21-22, 1966.
17. Houlb, L. D.: ”Application of High Pressure Dual Tubingless Completions and Low Cost Concepts in an Environmentally Sensitive Area,” IADC/SPE 35123, New Orleans, 12-15 March 1996.
18. Soetedja, V., Hunter, D.L.: ”Production Optimizating with Coiled Tubing and Other Rigless Techniques,” SPE 36963, Asia Pacific Mtg, Adelaide, Australia, 28-31 Oct. 1996.
19. Sutton, D.L., et.al.: ”Well Cementing Process and Gasified Cements Used Therein,” US Patent 4,340,427, (1982)
20. Cerruti, S.E.: ”Dual-Completion Design for HP/HT Corrosive Oil Well, Villafortuna-Trecate Italy,” SPE 28892, Euro Conf, London, 25-27 Oct 1994
21. Grassick, D.D., King, S.D.J.: ”Blowout Risk Analysis of Gas-Lift Completions,” SPEPE, May 1992.
22. Grassick, D.D., Kallos, P.S., Jardine, I.J.A., Deegan, J.: ”Risk Analysis of Single and Dual-String Gas-Lift Completion,” JPT November, 1980.
23. “King, G.E.: Surface Controlled and Subsurface Controlled Subsurface Safety Valves: Use in OnShore Wells,” an internal Amoco report based on industry literature.
24. Molnes, E.L., Rausand, M., Linquist, B.: ”ScSSV Reliability Tested in the North Sea,” PEI, Nov 1987.
25. Busch, J.M., Policky, B.J., Llewelyn, D.C.G.: ”Subsurface Safety Valves, :Safety Asset or Liability,” SPE 12193.
26. Sintef: Reliability of Surface Controlled Subsurface Safety Valves-Phase IV, STF75 F91038.
27. Deepstar II CTR 1010-1,” Surface Controlled Subsurface Safety Valves Risk Assessment,”
28. Molnes, E., Sundet, I.: ”Reliability of Well Completion Equipment,” SPE 26721.
29. King, G.E., Corgan, J.M., Perry, J.T., Powers, B.S.: ”Initiating Report on Pipe Cut-Off Techniques: Potential for Improving the Technology,” An internal Amoco Report.
30. King, G.E.: ”Evaluation of Downhole Cutting Methods for Severing Drill Pipe in Trinidad Well MA-08,” F99-P-8, February 11, 1999.
31. King, G.E.: ”Development of Technology Risk Values for Weighting Workover Economics, 1997 Update,” An Internal Amoco Report
32. Kirkpatrick, J., Cloud, M.: ”Tubing Conveyed Perforating, A Performance Evaluation,” Amoco Internal Report.
33. King, G.E.:”Evaluation of Tubing Perforating Puncher Charges in Tubing Selective Completions Through Gravel Packed Intervals,” An Internal Amoco Report33. King, G.E.:”Evaluation of Tubing Perforating Puncher Charges in Tubing Selective Completions Through Gravel Packed Intervals,” An Internal Amoco Report
34. Conversation and data from Dan Gibson, North Sea Operations
35. Barrilleaux, M.F., Colbert, J., King, G.E., Murugappan, B.: “Real Time Reservoir Management Using Intelligent Completions to Gather Data, Modify Flow Paths, Accelerate Recovery, and Optimize Flow in Multiple Pay Wells; Notes from an SPE Forum,” F98-P-19, July 16, 1998.
36. Soeprijadi, Hervochon, J., Nugraha, A., Noiray, J.M.: “Light Workovers in the Handil and Bekapai Fields,” Indonesia Pet. Assoc., 19 th Annual Convention, October, 1990. IPA90-174.
37. Aldridge, D.: “Multi Zone Completion Design,” SPE 35229, Permian Oil Conference, Midland, 27-29 March 1996.
38. Barua, S.: “Computation of Heat Transfer in Wellbores with Single and Dual Completions,” SPE 22868, Annual Tech. Conf., Dallas, Oct 6-9, 1991.
39. Davidson, J.A., Victors, C.M.: “An Overview of the Performance of Gas Lift Operations in the Ardjuna Fields, Indonesia Petroleum Proceedings, 15 th Annual Conv., Oct 1986.
40. Geyelin, J.L.: “Field Experience in Down Hole Annulus Safety Valves,” SPE 19278, Offshore Europe, 1989.
41. Tamimi, Y.K.: “Rigless Acid Fracturing Through Dual Completions: An Offshore Experience in the Upper Zakum Field,” ADNOC/SPE 21313,
42. VT between BP-Kuwait and Abu-Dhabi offices, 9/23/98
43. Information from E-mail from Mark Barrilleaux, experience on Exxon wells
44. Information from E-mail from Graham Beadie, experience on Abu Dhabi wells
45. Gyani, Angela, presentation on Asphaltenes
46. J. Faber, G. J. P. Joosten, K. A. Hashmi & M. Gruenenfelder, SPE 39633, presented at the SPE/DOE Improved Oil Recovery Symposium, Tulsa, OK, 22/04/1998. “Water shut-off field experience with a relative permeability modification system in the Marmul feld (Oman)”.
47. F. Legere, J. Cdn. Pet. Tech, October 1978, 51 - 60, ”Reduction of water - oil ratio using polyacrylamides in vugular carbonate reservoirs”
48. P. Hessert & P. D. Fleming, Third tertiary oil recovery conference, Wichita
49. D. Sydansk & T. B. Smith, SPE 17383 presented at the SPE/DOE EOR Symposium, Tulsa, OK, April 17 - 20, 1988, “Field testing of a new conformance - improvement - treatment Chromium (III) gel technology”
50. N. Senol, R. Gulumser & N. Tekayak,
51. D. Sydansk & P. E. Moore, 1991, SPE 21894,
52. D. Sydansk & P. E. Moore, Oil & Gas Journal, Vol. 90, Number 3, 40 - 45, January 20th 1992, “Gel Conformance treatments increase oil production in Wyoming”.
53. D. Moffitt, JPT, April 1993, 356 - 362
54. S. Seright & J. Liang, DOE/BC/14880-5, 95 - 140, December 1993, “Improved techniques for fluid diversion in oil recovery”
55. Gel Technologies Corporation treatment summary report for Marathon Oil Company Big Lake Field, Reagan County, Texas University NO 208, January 1994.
56. P. Southwell & S. M. Posey, SPE 27779, SPE/DOE 9th Symposium on IOR, Tulsa
57. C. Borling, SPE 27825, SPE/DOE 9th Symp. on IOR, Tulsa , April 17 - 20, 1994, “Injection conformance control case histories using gels at the Wertz field CO2 tertiary flood in Amoco Wertz field, Wyoming”.
58. D. Sydansk & G. P. Southwell, SPE 49315, Ann. Tech. Conf. & Exhibn., New Orleans, Sept 27 - 30, 1998. “More than 12 years of experience of successful Conformance - control polymer gel technology”
59. I. Tweidt et al, SPE 38901, SPE Ann. Tech. Conf. & Exhibition, San Antonio October 5 - 8, 1997. “Improving sweep efficiency in the Norman Wells naturally fractured reservoir through the use of polymer gels”. Plus notes.
60. Randy Seright, New Mexico PRRC 1997
61. Personal communication from BP Kuwait.
62. Grassick, D.D., Kallos, P.S Dean, S., King, S.D.J.: “Blowout Risk Analysis of Gas-Lift Completions,” SPE Prod Eng., May 1992, p172.
63. Grassick, D.D., Kallos, P.S., Jardine, I. J. A., Deegan, F.J.: “Risk Analysis of Single and Dual-String Gas-Lift Completions,” JPT, Nov. 1990.
64. 13 Cr Running Time - Cross Assets Comparisons - Forties Case
65. Cameron, Paul: “Total-Fina-Elf - BP Northern BU,” Meeting Slides, 14 March 2002.
66. Gibson, Dan: “Data on 60 well study in North Sea (1999) and 25 well study in Forties (2001)
Intervention Data – Stat. Fail. Freq.
The following average MTTF are used (* indicates initial valuesgiven prior to adjustment to reflect ‘critical failures’ only):
Read the definitions and explanations of MTBF and the limits ofStatistical frequency before inferring rates from this data.
Xmas tree replacement: 250 yrs (* 50 yrs) Xmas tree replacement: 250 yrs (* 50 yrs)
SCSSV wireline insert: 83 yrs (* 17 yrs)
SCSSV replacement: 111 yrs
GLV critical failure: 50 yrs (*10 yrs)
Upper completion repair: 100 yrs
Upper completion replacement: 100 yrs
Lower completion repair: 50 yrs
Lower completion replacement: 33 yrs
15