well planning presentation
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Well PlanningWell PlanningPresentation 6Presentation 6
DRILLING TECHNICIAN SCHOOLDRILLING TECHNICIAN SCHOOL ExxonMobil Development CompanyExxonMobil Development Company
Houston, TexasHouston, Texas
20042004
Fred E. DupriestTechnical Operations Support
Learning Objectives and Outline /Overview
Step 1: Establish team
Step 2: Collect and Display Well Data
Step 3: Select casing setting depths
Step 4: Select casing sizes and configuration
Step 5: Determine the directional profile
Step 6: Optimize performance
Step 7: Eliminate Invisible Time
Step 8: Other design/operational issues
Detailed Designs Not Covered
• Rig analysis / specification
• Site and regulatory issues
• Environmental and industrial hygiene
• Shallow hazards study
• Risk assessment
These topics are covered in separate lectures.
• Mud program
• Bit selection
• Cement design
• Wellhead and tubulars
• Well control equipment
• Formation evaluation
Step 1: Establish Team
Characteristics of High-Performing Teams
• High-performing teams have an inclusive culture
– Everyone knows and agrees on the important objectives
– People listen to each other and express themselves
– Disagreements are resolved through logical discussion
– Don’t withdraw under stress
• Team leaders exhibit team behaviors and achieve it in others by setting the right example
• Team behaviors lead to better decisions and execution, but a sense of individual responsibility must be maintained
Step 2: Collect and communicate well data
Well Planning Package
• Well Planning Data is an OIMS Element 3 requirementWell Planning Data is an OIMS Element 3 requirement
• Obtain well requirements from client in writingObtain well requirements from client in writing
• Exact content is not specified by OIMS and varies Exact content is not specified by OIMS and varies between groupsbetween groups
• The most critical element is the Bottom Hole Pressure The most critical element is the Bottom Hole Pressure sheet. sheet. Do not drill a well without a bottom hole pressure sheet.
Bottom Hole Pressure Sheet
• Confirm that offset pressures are recentConfirm that offset pressures are recent
• Obtain estimates of the draw down at Obtain estimates of the draw down at your locationyour location (not the pressure at the offset well)(not the pressure at the offset well)
• Plan sufficient overbalance to allow tripping without Plan sufficient overbalance to allow tripping without swabbingswabbing
• Adjust MW for structural position (the shallower you Adjust MW for structural position (the shallower you drill the formation, the higher the MW required)drill the formation, the higher the MW required)
Adjusting MW for Structural Position
Gas Column(2.0 ppg)
Water Column
16.0 ppg10,500 ft
??? ppg10,000 ft
If 16.0 ppg is required at 10,500 ft, what MW is required at 10.000 ft?
(16.0)(10500)(.052)-(2.0)(500)(.052)(10000)(.052)
= 16.7 ppg
Well #2 Well #1
Collect Useful Offset Data
• Infield well data– Well files
• Daily Reports • Stick Charts• Procedures (trouble mitigation)
– Follow-up reports– Field studies– Scouting information– Log headers
Collect Useful Offset Data
• Non-proprietary service company data
– Bit records
– Mud records
– Directional drilling summary reports
– Request a design proposal. The service company will build their experience into the plan.
• Published offset performance data– SPE and other Trade Journals
– Government publications
Industry Database (PetroConsultants)
Collect Useful Offset Data - Cont’d
• EMDC Drilling OBO Group - Partner DataEMDC Drilling OBO Group - Partner Data– Project proposals and well planning meetingsProject proposals and well planning meetings
– Detailed drilling proceduresDetailed drilling procedures
– Daily surveillance and partner meetingsDaily surveillance and partner meetings
• Corporate memoryCorporate memory– Who drilled the last well?Who drilled the last well?
– Who drilled the best well?Who drilled the best well?
Collect Useful Well Data
• Direct contact with offset operators
– Inform client organization of proposed contact
– Follow legal guidelines established by local management
– Be prepared to exchange data similar to what you’re requesting
– The drilling engineer you want can usually be located with 3 phone calls. Start with Corporate Information and ask for the Drilling Group
Displaying Data
• Morning ReportsMorning Reports– DRS or Hard Copies on Rig DRS or Hard Copies on Rig – Stick chartsStick charts
• GraphsGraphs– Days vs. depthDays vs. depth– Mud weight vs. depthMud weight vs. depth
• Geologic DataGeologic Data– Cross-sectionCross-section
– Structural mapsStructural maps
– Annotated logsAnnotated logs
Stick Charts
KR Laguna Larga 134200 ft to South,drilled Jan 1976
TD = 8,662’
no information
9-5/8” @ 8,998’ PIT=19 ppg
13-3/8” @ 2,052’ PIT = 14 ppg
17 ppg mud gas cut to 16 ppg7-5/8” liner @ 10,575’ PIT = 19.5 ppg
5” x 5-1/2” @ 12,760’ran to bottom OK
17.8 ppg
17.8 ppg
11.4 ppg
11.4 ppg
15.0 ppg
16.0 ppg17.0 ppg
multiple gas shows
10,593’ – Well kicked with 17.1 ppg, lost returns with 17.7. Spotted LCM and re-established circulation with 17.6 ppg. Ran liner to 10,575’.
10,100’ - 10,330’ – Sands at 13 - 14 ppg, probable cause of LC below.
9 ppg
9 ppg
oil show @ 7,600’hole tight on bottom
KR Laguna Larga 533030 ft to West,drilled Oct 1988
multiple gas shows, mud cuts to 16.8 ppg
10,600 – Core 30’, 90% recovery. gas shows, no actual flows
11,267 – DP twisted off, recovered.multiple gas shows, mud cuts to 17.2 ppg
12,120 – Core 38’, 89% recovery.mud cut to 16.8 ppg
TD – 56 side-wall cores cut; mud losses while logging = 2-3 bbl/run.
no problems, no gas
no problems
KR Laguna Larga 202750 ft to West,drilled Aug 1978
TD = 8,748’
8-5/8” @ 1,580’9 ppg
9.5 ppg
9.2 ppg
10 ppg
11 ppg
11.5 ppgP&A
no problemsreported, noshows mentioned
Days vs. Depth
00
500500
10001000
15001500
20002000
25002500
30003000
35003500
40004000
4500450000 1010 2020 3030 4040 5050 6060 7070 8080 9090 100100 110110 120120 130130 140140 150150 160160 170170 180180 190190 200200
DaysDays
Mea
sure
d D
ep
th (
m-B
RT
)M
easu
red
De
pth
(m
-BR
T)
Step 3: Select Casing Setting Depths
Common Casing Strings
ConductorCasing
Structural Casing(Usually Subsea)
SurfaceCasing
Protective/Intermediate
Casing
Tubing
ProductionCasing
Liner
Structural Casing
• Subsea Wells (250-350 ft BML)– Stabilize formations near the seafloor
– Prevent excessive washout of near-seafloor material
– Typically washed into place
• Jackup Wells– Used to add bending strength for free-standing offshore
wells without supporting frames (e.g. Mobile Bay)
Conductor Casing
• Structural support for weight of diverter
• Shoe integrity for diverting operations
• Shoe integrity for hydrostatic head in riser
• Isolate formations with a history of caving
• May be based on achievable drive depth (formation hardness), or rathole limitations (water)
Conductor Setting Depth
• Adequate depth for structural support for weight of riser and diverter
– Dependent on shear force on surface of pipe if driven
– Cement support if cemented
• Required shoe integrity adequate for likely pressure in diverter lines during well control (Typically < 150 psi)
• Integrity greater than the hydrostatic head in the riser (Typically < 200 psi)
• Use historical practice
Production Deck
Sea Level
Mud Line
Diverter
Diverter Lines
Flowline
Support due to shear force
Shoe integrity dueto overburden
Conductor Setting Method
Land (40-100 ft BGL)• Pre-installed with rathole machine,
and grout or circulate cement• Driven if ground water is present• Drill and run casing in hard rock
Jackup/Barge (80-300 ft BML)• Virtually all are driven to refusal• Drill and run casing in hard rock (rare
offshore)
Floater (300-1000 ft BML)• Drill hole then run casing with rig• Wash/drill casing into soft seafloor
Diverter
Diverter Lines
Flowline
Driven,Ratholed,
orDrilled
Surface Casing
• Primary purpose in onshore wells is to protect fresh water
– Depth is usually specified by regulatory authorities
– Run electric logs if depth of FW is not known < 1 ohms is typically SW > 3 ohms is typically Fresh Look for significant shift in conductivity
– May set deeper than FW if required for integrity Conduct risk assessment on FW contamination Seek regulatory approval High-quality cement across FW/SW interface
• Depth offshore based on integrity required for BOPs
Surface Casing
• Shoe integrity is critical
– Prevent contamination of FW by hydrocarbon due to underground flow
– Hydrocarbon is often exposed in the next interval
– Prevent broaching to surface or seafloor (common minimum is 800’-1000’ BML or BGL)
– Withstand MW required to drill into the abnormal pressure ramp to set the protective string (if any)
Protective Casing
• Depth determined by:
– Pressure and integrity gradients
– Lost returns zones
– Formation instability
– Doglegs and keyseats
– Required changes in drilling fluid
– Drag reduction (directional wells)
– May serve as Production casing above liner
Protective Casing Depths
VerticalVerticalDepthDepth
Eq Mud WeightEq Mud Weight
Pore Pressure andOperating Margin
Mud WeightMud Weight Integrity andOperating Margin
Plot Pressure
VerticalVerticalDepthDepth
Eq Mud WeightEq Mud Weight
Pore Pressure andOperating Margin
• Plot pore pressure from:– BHP Sheet– Production test data– FT test results– Estimates of production drawdown– Seismic velocity overlays– Offset drilling MW– Offset well control events
• Add 0.5-1.0 ppg for operating margin
?Csg
Depth
Adjust Pressure Data
• When using offset data, ensure pressures are adjusted for
– Differences in depth of formation
– Fluid column heights (gas, oil, or water)
– Proximity of producing wells that are drawing down formation pressure
Plot Integrity
VerticalVerticalDepthDepth
Eq Mud WeightEq Mud Weight
Integrity andOperating Margin
• Plot integrity from:• Offset LOT test data
• Offset lost returns events
• Methods of estimating integrity based on pressure draw down
• Methods of estimating integrity based on comparative rock properties
• Regional integrity curves
• Subtract Operating Margin for anticipated ECD and Surge
Casing Design Line
VerticalVerticalDepthDepth
Eq Mud WeightEq Mud Weight
Pore Pressure andOperating Margin
Casing DesignLine
Integrity andOperating Margin
Surface Csg
Casing Design Line
VerticalVerticalDepthDepth
Eq Mud WeightEq Mud Weight
Pore Pressure andOperating Margin
Casing DesignLine
Integrity andOperating Margin
Casing Design Line
VerticalVerticalDepthDepth
Eq Mud WeightEq Mud Weight
Pore Pressure andOperating Margin
Casing DesignLine
Integrity andOperating Margin
Casing Design Line
VerticalVerticalDepthDepth
Eq Mud WeightEq Mud Weight
Pore Pressure andOperating Margin
Integrity andOperating Margin
Theoretical MWRange
Class Exercise #1
• Selection of protective casing depths based on anticipated pressure and integrity
Production Casing
• Specified by the client organization
– Sufficient rathole to run logging tools below pay zones
– Meet client’s needs for rathole between bottom of perforations and the casing float collar (gun junk, frac sand, etc.).
• Ensure client is specifying the minimum rathole required.
• Rathole for tools should be in MD, not TVD.
• Drilling out float joints and set retainer above shoe if adequate rathole cannot be drilled.
Ratholefor openhole logs
Rathole inside casing for cased hole logs, frac
sand, or Junk
LowestPay Zone
Step 4: Select Casing Sizes and Configuration
General Guidelines
• Start with the final string to be run (tubing), and work backward up the hole
1
4
3
2
6
5
What size of tubing has been requested?
What size casing is it practical to put tubing in?
What size casing will bit for next hole fit through?(Assuming the next hole is not underreamed)
What size hole is it practical to put casing in?
What size hole is it practical to run casing in?
What size casing will bit for next hole fit through?
Example Casing Programs
North SeaNorth Sea Gulf of MexicoGulf of Mexico
HoleHole Csg.Csg. HoleHole Csg.Csg.
DrivenDriven 3030 2626 2020
2626 2020 17-1/217-1/2 13-3/813-3/8
17-1/217-1/2 13-3/813-3/8 12-1/412-1/4 9-5/89-5/8
12-1/412-1/4 10-3/4 x10-3/4 x
9-5/89-5/8
8-1/28-1/2 77
Tubing Size
• Client typically specifies tubing size requirement– Optimized flow and economics over life of well– Critical gas velocity limitations for carbon steel
• Use CRA materials (typically 18-Chrome)• Use larger tubing to reduce velocity
• Select production casing to accommodate– OD of client’s preferred tubing connection,– Client’s tubing workover experience. How large a
connection can they practically work with?– Gravel pack clearance needs– Production packer with full opening ID
• Rely on industry convention and field history
General Guidelines - Cont’d
• Utilize “normal” clearance designs as the base case
• “Low” clearance designs are considered if:– Well economics require cost reduction– Normal clearance design does not allow enough strings to
be run to reach objectives– Offset experience confirms feasibility.
Casing Size Run Normal Clearance Low Clearance
5-1/2” 8-1/2” Hole 6-1/2” Hole
7-5/8” 9-7/8” Hole 8-1/2” Hole
9-5/8” 12-1/4” Hole 10-5/8” Hole
Normal vs Low Clearance
20”
13-3/8” Csg
9-5/8” Csg
7” Csg
5” Csg
17-1/2 HL
12-1/4” HL
8-1/2” HL
5-7/8” HL
24”
16” Csg
9-5/8” Csg
7-5/8” Csg
5-1/2” Csg
11-3/4” Csg
17-1/2”HL
10-5/8” HL
8-1/2” HL
6-1/2” HL
14-3/4” HL
NormalNormal LowLow
Casing and Hole Size
• Low clearance designs may increase the probability Low clearance designs may increase the probability of stuck casing, lost returns due to ECD, and of stuck casing, lost returns due to ECD, and cement channeling due to poor mud displacement. cement channeling due to poor mud displacement. A combination of issues must be managed:A combination of issues must be managed:
– Ream potential sticking zones to reduce filter cakeReam potential sticking zones to reduce filter cake– Compare calculated surge and ECD to hole integrityCompare calculated surge and ECD to hole integrity– Utilize integral joint casing (upset typically < 1/4”)Utilize integral joint casing (upset typically < 1/4”)– Centralize casing heavily to prevent wall contactCentralize casing heavily to prevent wall contact– Moderate, uniform, hole enlargement with WBM may be Moderate, uniform, hole enlargement with WBM may be
preferred to gauge hole with OBMpreferred to gauge hole with OBM– Consider use of autofill equipment to reduce surge Consider use of autofill equipment to reduce surge – Drill interval with packed BHA to prevent bit dartingDrill interval with packed BHA to prevent bit darting
Ensure Effective Hole Size (EHS)
EHSEHS
EHS = Bit O.D. + O.D Above Bit2
If EHS is < OD of Casing:• Increase collar size
• Run oversized bit sub
• Run small stabilizer above bit
• Run packed assembly
• Use PDC with long gauge
BitBitODOD
OD AboveOD AboveBitBit
Class Exercise #2
Effective Hole Size Concepts Hole Size Concepts
UnderreammingUnderreamming
• If additional strings are desired and low casing/hole If additional strings are desired and low casing/hole clearance is not acceptable due to surge or clearance is not acceptable due to surge or directional doglegs, enlarge the initial holedirectional doglegs, enlarge the initial hole
• The method use to enlarge the hole must be The method use to enlarge the hole must be determined during preliminary planning because it determined during preliminary planning because it may have a large impact on rig days, and well may have a large impact on rig days, and well costs.costs.
– UnderreamingUnderreaming– Bicenter bitsBicenter bits
– Ream while drilling (RWD) and steerable ream while Ream while drilling (RWD) and steerable ream while drilling tools (SRWD)drilling tools (SRWD)
Liner vs. Long String
LinerLiner LongLong StringString
Liner vs. Long String
• Long String AdvantagesLong String Advantages– Potential lower total cost if rig rate is high - less rig timePotential lower total cost if rig rate is high - less rig time
• Long string operation, 1-2 daysLong string operation, 1-2 days• Liner operation, 3-4 days Liner operation, 3-4 days
– Reduced risk of mechanical failureReduced risk of mechanical failure• No downhole moving partsNo downhole moving parts• Higher wiper plug reliabilityHigher wiper plug reliability
– Reduced completion costsReduced completion costs• Eliminates potential liner top leakEliminates potential liner top leak• Multiple trips to clean liner and upper casing IDMultiple trips to clean liner and upper casing ID
Liner vs. Long StringLiner vs. Long String
• Long String Advantages - Cont’d
– Reduced requirements for protective casing• Reduced burst• Potentially use Non-CRA protective in mild H2S if
OBM is used, then cover protective with smaller CRA ($) production casing
– Pipe movement while cementing• Liners are typically set before cementing, and can
only be rotated. Rotational force is limited by connections
• Long strings are typically reciprocated and the tensile limit of the casing can be applied to initiate movement
Liner vs Long String
• Liner AdvantagesLiner Advantages– Less casing ($)Less casing ($)
– Potential reduced ECD while running and cementingPotential reduced ECD while running and cementing• Also often run autofill equipment with linersAlso often run autofill equipment with liners
– Open liner top facilitates cement repair after lost returnsOpen liner top facilitates cement repair after lost returns
– Ability to set liner top packer to shut off annular gas Ability to set liner top packer to shut off annular gas flowflow
– Allows tapered string with larger tubing above liner topAllows tapered string with larger tubing above liner top
– Increased tubing size through use of PBR (Monobore)Increased tubing size through use of PBR (Monobore)
Monobore Designs
• Monobores have a single inside Monobores have a single inside diameter from surface to TD.diameter from surface to TD.
• A liner is set through the pay zoneA liner is set through the pay zone• A tubing string of the same diameter is A tubing string of the same diameter is
stung into a tie-back receptacle in the stung into a tie-back receptacle in the liner topliner top
• Provides the largest tubing size and Provides the largest tubing size and least flow restrictionleast flow restriction
• The tieback can be larger than the liner, The tieback can be larger than the liner, if desired, because lower clearance can if desired, because lower clearance can be used inside casing than in open holebe used inside casing than in open hole
Tubingless Wells
• Tubingless wells produce up the Tubingless wells produce up the production casing. The casing itself is production casing. The casing itself is often a tubing size (2-7/8” or 3-1/2”)often a tubing size (2-7/8” or 3-1/2”)
• Inexpensive wells in marginally Inexpensive wells in marginally economic playseconomic plays
• Tubing leaks cannot be repaired easily, Tubing leaks cannot be repaired easily, used primarily in dry gas with no history used primarily in dry gas with no history of corrosionof corrosion
Step 5: Determine the Directional Profile
Simple Directional Profiles
Build and holdBuild and hold S-turnS-turn HorizontalHorizontal
Simple Well Profiles
• Easy to drill– Two dimensional trajectory (B&H, S-Curve or Horizontal)– Avoid long intervals below 20° angle. Angle will be eratic
• Compatible with the casing program– Avoid casing seats in angle-change intervals– Avoid high doglegs in shallow sections of deep wells
• Compatible with geology– Avoid directional changes in hard formations– Drill S-curves before entering hard rock, if possible– Avoid high angles in unstable shales– Review entire path with Geology, not just target
penetration
Step 6: Optimize performance
Key Historical Performance Design Issues
• Plan to conduct as may activities offline as possible• Minimize overbalance • Minimize hole size. Consider low clearance designs • Run long strings in preference to liners • Replace wireline logs with LWD • Minimize sliding in directional corrections
– Lead directional targets to allow natural walk– Drill S-Curves to complete directional work in soft rock– Utilize rotary steerables
• Contract rig with adequate pumps to clean hole • Take a zero-tolerance approach to stuck pipe
Maximizing Drill Rate
Drill rate is maximized when all of the drilling energy reaches the rock below the bit. Loss of energy may occur through:
• Bit Balling
• Bottom Hole Balling
• Drill String Vibrations
• Bit Vibration
• Friction and Stick Slip at High Angle
• Hole Cleaning and Drag in Cuttings Bed
Bit balling is by far the largest problem
PDC Bit Balling
Cuttings on the face of blade carry some of the bit load if they are not removed efficiently
Weight carried by solids build-up reduces force on the cutting structure
LamellaeLamellae
PDC Cuttings and Bit Balling
DEA 90 Data
WOB and Bit Balling
ROP
WOB
ObservedField Behavior
ROP Increase Proportionate to WOB
Bit Balling and Flounder Point
ROP
WOB
100% efficiency
ObservedField Behavior
Bit Balling (Flounder Point)Drill cuttings are reducing weight transmitted to cutting structure
Bit Balling and Theoretical Performance
ROP
WOB
100% efficiency
Loss of efficiency
and ROP
Theoreticalperformance
60 rpm
80 rpm
70 rpm
Field Behavior Matches Theoretical(Computer Aided Test - Tooth Bit)
ROP increases proportionately to RPMROP increases proportionately to RPM ROP increases proportionately to WOBROP increases proportionately to WOB
Linear Response to RPM
0
10
20
30
40
50
60
40 50 60 70 80 90RPM
RO
P
17 fpm
30 fpm
48 fpm
Data from Drilloff Tests on Preceding Page
At 40 ksi WOB
Drilling Rate Tests
WO
BR
OP
RP
M
DEA 90 Data
Depth
TO
R
Depth
Balling at 10 ksiNo Balling at 30 ksi
“Firm” Rock “Sticky” Rock
Design Mitigations for Bit Balling
• DrillOff or Drill Rate tests to define balling limits• Utilize NAF• Utilize inhibitive WBM• ROP Enhancers in WBM < 14 ppg (3-6% by vol)• High hydraulics in WBM (HSI 4-6 hp/in2)• Bit designs that direct hydraulics more
efficiently• Extended nozzles• Vortex nozzles• Maximize bit open face volume (minimum PDC
blade required for durability)
Bottom Hole Balling in Hard Rock
Hard, brittle rock expands when crushed and develops low pressure in the crush zone. Differential pressure into the crush zone creates filter cake and holds material down
..
Hard RockHigh P
Filter cake and reworked material
Porosity expansion and crush zone
Bottom Hole Balling Mitigation
Drill rate during Bottom Hole Balling is controlled by rate of pressure penetration into the powder (filtrate invasion). Much more difficult to eliminate than bit balling.
• Minimize MW (reduce powder hold-down pressure)
• Drill with clear water (no filter cake)
• Drill underbalanced
• Drill with air
• Utilize high speed turbines
Design Mitigations for Vibrations
• Anti-whirl bits
• Low vibrations BHA arrangements
• Utilize BHA Rez to determine stabilizer spacing
• Minimize number of stabilizers
• Roller Reamers
• Soft Torque
• Reduce PDC cutter size and reduce number
• Reduce drill string RPM by running motor or turbine
• Rotary steerable
• Increase collar size
• Use single 60 foot pendulum rather than 60/90
Step 7: Eliminate Invisible Time
Probability-Case Model
P-50 Days
Days
Pro
bab
ilit
y
P-0 Days P-80 Days
Technical Limit (A Performance Model)
EarlyLearning Curve
Learning CurveCompression
Technical Limit
Theoretical Limit
Long-TermLearning Curve
Actual Well Duration
Industry Normal Well Time
Theoretical Time Invisible Lost Time Conventional NPT
Removable Time
Consecutive Wells
Eliminate Invisible Time
Increased performance typically requires a change in operating practices, not new technology. The decision to eliminate invisible time is strongly dependent on the perception and mitigation of risk. Examples:
Wiper trip at 24 hrs Wiper trip only on observed torque or dragPump out of hole on trips Model HCR, pump out only when HCR < 1.1Scrape casing and run retainer Squeeze open ended Use drill collars for bit weight in vertical Use HWDP in vertical hole < 8-1/2”Control drill < 100 fph Control drill < 200 fphDrill out with roller cone, then trip for PDC Drill out with PDCDrill out and trip for directional assembly Drill out with MWD and steerable motorUnderream pilot hole for additional clearance Run low-clearance casing/hole designProduce test oil to barge Flare produced test oil offshoreHold pressure on liner top cement Rely on cement design to prevent annular gas flow Replace drill pipe with HWDP in horizontal Run drill pipe in compression in horizontal Control drill to minimize drill gas Install rotating head and drill with 2000 units gasWait on after-flow to stop completely Establish ballooning trend, make connections w/flow
More Costly/ Less RiskMore Costly/ Less Risk Less Costly/ Higher RiskLess Costly/ Higher Risk
Step 8: Other Design/Operational Issues
Potential Additional Costly Design Issues
• Safety (primarily H2S)
• Evaluation Program (coring, testing, logging)• Rig availability and suitability
– Mob/Demob cost– Derrick, substructure and drawworks rating– Pump capabilities
• Environmental– Site and location access plan– Disposal plan
• Transportation logistics
Potential Additional Design Issues - Cont’d
• Weather window and downtime• Mitigation of historical trouble and NPT, such as:
– H2S
– Hole stability– Lost returns– Stuck pipe– Formation damage– Chronic BHA failures– Failure to achieve formation evaluation– Primary cement failure during production– Sand production
Summary
Step 1: Establish team (Functional Relationships)
Step 2: Collect and Display Well Data (Thorough Research, Effective Communication)
Step 3: Select casing setting depths (Integrity Driven)
Step 4: Select casing sizes and configuration (Casing Cost
vs. Rig Time, vs. Risk)
Step 5: Determine the directional profile (Torque and Drag)
Step 6: Optimize performance (Mitigate Bit Balling or
Bottom Hole Balling)
Step 7: Eliminate Invisible Time (Mitigate Change/Risk)
Step 8: Other design/operational issues
top related