Well Planning Presentation

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




• 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



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




Casing DesignLine


Surface Csg

Casing Design Line




Casing DesignLine


Casing Design Line





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

Well Planning Presentation

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