directional survey

UpstreamTechnology

Group

ISSUE 1SEPTEMBER 1999

BP AmocoDirectional Survey Handbook BPA-D-004

September 1999 Issue 1 i

Contents

Authorisation for Issue

Preface

Amendment Summary

Section 1 Introduction1.1 About this Handbook

1.2 Directional Survey and Value Addition

1.3 The Design-Execute Principle

Section 2 Policy and Standards2.1 Drilling and Well Operations Policy

2.2 Policy Expectations

2.3 Standard Practices

Section 3 Theory3.1 Surface Positioning

3.2 The Earth’s Magnetic Field

3.3 Position Uncertainty

3.4 Position Uncertainty Calculations

Section 4 Methods4.1 Multi-Well Development Planning

4.2 Survey Program Design

4.3 Anti-Collision – Recommended Practice

4.4 Anti-Collision – Selected Topics

4.5 Target Analysis

4.6 Survey Calculation

4.7 In-Hole Referencing

4.8 In-Field Referencing

4.9 Drill-String Magnetic Interference

4.10 Survey Data Comparison

BP AmocoBPA-D-004 Directional Survey Handbook

ii Introduction September 1999 Issue 1

Contents (cont’d)

Section 5 Survey Tools5.1 Inclination Only Tools

5.2 Measurement While Drilling (MWD)

5.3 Electronic Magnetic Multishots

5.4 North-Seeking and Inertial Gyros

5.5 Camera-Based Magnetic Tools

5.6 Surface Read-Out Gyros

5.7 Dipmeters

5.8 Obsolete and Seldom Used Tools

5.9 Depth Measurement

5.10 JORPs

Section 6 Technical Integrity

6.1 What is Technical Integrity ?

6.2 Risk Assessment

6.3 Surface Positioning

6.4 The Directional Design

6.5 Executing the Design

6.6 Survey Data Management

6.7 Performance Review

Appendix A Mathematical Reference

Appendix B Approved Tool Error Models

Appendix C Data and Work Sheets


September 1999 Issue 1 v/vi

Preface

This Issue 1 of the BP Amoco Directional Survey Handbook (BPA-D-004)is applicable in all areas of the BP Amoco organisation.

In addition to the uncontrolled hard copies, this document is alsoavailable online via the wellsONLINE and ASK websites, accessible onthe BP Amoco Intranet. The online document is to be considered themaster version, containing the most up-to-date information.

The distribution of this document is managed by the UpstreamTechnology Group (UTG) and controlled and administered in Aberdeenby ODL.

ODL may be contacted as follows:

UTG DCC or: UTG DCCODL ODL MailboxBuchanan House BP Amoco, Dyce (through internal mail)63 Summer StreetAberdeen AB10 1SJScotland

Tel 44 (0)1224 628007Fax 44 (0)1224 643325

Alternatively, contact the UTG Wells Document Controller,Steve Morrison at BP Amoco, Dyce, Extn 3593 (44 (0)1224 833593


September 1999 Issue 1 vii/viii

Amendment Summary

Issue No Date Description

Issue 1 Sept 1999 First issue of document.


September 1999 Issue 1 Introduction 1-i/ii

Section 1

Contents

Page

1-1

1-2

!"# 1-6

Figure

1.1 Well positioning process and associated files 1-7


September 1999 Issue 1 Introduction 1-1

Who this Handbook is for, and whatit’s about.

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Reference toanother sectionin the Handbook

Reference to atechnical paperor publication

Indicates a BPAmoco StandardPractice


1-2 Introduction September 1999 Issue 1

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The well’s surface position must be directly above or at aknown horizontal offset from the geological target locatedby the seismic survey, often taken months or years before.

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The wellbore must be drilled such that it intersects an oftensmall and distant geological feature.

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The wellbore must not hit any existing wells which liebetween it and the target.

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Examining any question or decision about well positioningagainst this principle is almost guaranteed to help in itsresolution.

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The purposeand content of theDirectional Design

and Well Survey Filesare explained in

Sections 6.4 and 6.6


September 1999 Issue 1 Introduction 1-7/8

Identify geological target(s)

Formalise well objectivesand planned surface and

target locations

Design directional planand survey program

Position rig atsurface location

Acquire and validatesurvey data per program

Compile definitive well surveyand load to database

Final WellPosition Memo

Defintivewell survey

Survey reports

Well Survey File

Well LocationMemorandum

Final proposedtrajectory and

survey program

DirectionalDesign File

Well Data Packor similar

Figure 1.1

Well positioningprocess andassociated files


September 1999 Issue 1 Policy and Standards 2-i/ii

Section 2

"

Contents

Page

3$#" 2-2

" !# 2-3

" 2-9


September 1999 Issue 1 Policy and Standards 2-1

" What BP Amoco Policy says aboutdirectional surveying and what itmeans for your Business Unit.

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2-2 Policy and Standards September 1999 Issue 1

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(12.5) A database of well trajectories (planned and actual)and all project data (slots, targets, locations andprojections) shall be maintained in a form approved by aqualified person appointed by BP Amoco Senior DrillingManager. This safety-critical database shall be the subjectof a written plan approved by BP Amoco that describes howit shall be managed throughout the Business Unit life cycle.

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(8.4) The final position of all spud locations shall beconfirmed by a qualified surveyor.

(8.8) The rotary table elevation, relative to seabed at meansea level and water depth (offshore drilling units) or therotary table elevation relative to ground level (land drillingrigs) shall be determined and formally recorded.



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(12.1) Survey programs for all wellbores shall be designedsuch that the wellbore is known with sufficient accuracy to:

a) Meet local government regulations

b) Penetrate the geological target(s) set in the well’sobjectives

c) Minimise the risk of intersection with any nearbywellbore

d) Drill a relief well

(12.2) The performance specification of all instrumentsemployed on operations shall be approved for the use by aqualified person appointed by BP Amoco Senior DrillingManager.

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(12.6) On multi-well operations a collision check shall beperformed on the planned well trajectory

(12.7) All procedures for assessing tolerable risks ofcollision, defining minimum well separations and ensuringcompliance with such criteria while drilling shall beapproved by a qualified person appointed by BP AmocoSenior Drilling Manager.

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September 1999 Issue 1 Theory 3-i

Section 3

Contents

Page

'" 3-1

51+ 3-17

"( 3-21

4 "(& 3-26

Figure

3.1 The Earth’s surface and the geoid 3-2

3.2 Globall y and locall y fitting ellipsoids 3-3

3.3 Dependence of latitude on choice of ellipsoid and datum 3-3

3.4 Relationship bet ween geodetic heights 3-5

3.5 Geographical, mapping grid and drilling grid co-ordinates 3-7

3.6 Variation of grid scale factor across a mapping grid 3-8

3.7 Components of the magnetic field vector 3-18

3.8 The one dimensional normal distribution 3-23

3.9 A two dimensional distribution resolved in t wo directions 3-24

3.10 Principal directions and the standard error ellipse 3-25


3-ii Theory September 1999 Issue 1

Section 3

Contents (cont’d)

Table Page

3.1 Definition of the drilling grid in someBP Amoco operation areas 3-9

3.2 The magnetic field in some of BP Amoco’s operating areas(approximate values as of 1 Jul y 1999) 3-19

3.3 Confidence intervals for the one dimensionalnormal distribution 3-23

3.4 Confidence intervals for the t wo dimensionalnormal distribution 3-25

3.5 Error term propagation modes 3-27


September 1999 Issue 1 Theory 3-1

An introduction to the science of wellsurveying.

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3-2 Theory September 1999 Issue 1

Ocean

The Earth

Mountain Range

Geoid

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Figure 3.1

The Earth’s surfaceand the geoid



geoidglobally fittingellipsoid

eg. WGS 84

locally fittingellipsoid

eg. Clarke 1866

area of bestfit of ellipsoid

to geoid

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blacklatitude

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Figure 3.2

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Figure 3.3

Dependence oflatitude on choice ofellipsoid and datum



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Relationship betweengeodetic heights



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Central Meridian

drilling grid lines of latitiudeand longitude

mapping grid

Cross-sectionshown infigure 3.6

West of theCentral Meridian, grid convergence

is negative

East of theCentral Meridian, grid convergence

is positive

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When survey measurements are related to grid north it isessential that the relevant map grid (projected co-ordinatesystem, including geodetic datum) is identified.

Figure 3.5

Geographical,mapping gridand drilling gridco-ordinates



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mapping projectionEarth’s Surface (Spheroid)

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0

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Variation of grid scalefactor across a

mapping grid

BP AmocoStandard Practice




3 " % " " " $$# & "#$ #%""" " &

structureref. point

drilling grid north(DGN)

Structure Centred Referencing Survey Reference = True Northdrilling datum

(= rotary table)A

Well Centred Referencing Survey Reference = True North

DGN

B

Structure Centred Referencing Survey Reference = Grid NorthC DGN

Well Centred Referencing Survey Reference = Grid NorthD

DGN

(MAPPING)GRID

NORTH

TRUENORTH Norway

UK - FortiesUK - MagnusUK - former Amoco

UK - former BP (excluding Forties, Magnus)Netherlands

USA - Gulf CoastUSA - LandColombia

USA - Alaska

Table 3.1

Definition of thedrilling grid in someBP Amoco operatingareas



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Section 3.3explains the statistical

concepts behindposition uncertainty

Section 4.2 givesthe surveying

requirements for reliefwell contingency



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Figure 3.7

Components of themagnetic field vector



1"#$ $ 5 " $ ""!8 $&1 $ " ; " % # $"" "$ $&

Location Lat. Long. Declination DipAngle

FieldIntensity

HorizontalIntensity

Vietnam 8°N 109°E 0° 0° 41,000 nT 41,000 nT

Abu Dhabi 24°N 54°E 1°E 36° 43,000 nT 34,000 nT

Egypt 28°N 33°E 3°E 41° 42,000 nT 32,000 nT

Kuwait 29°N 48°E 3°E 44° 44,000 nT 32,000 nT

Algeria 29°N 1°E 2°W 39° 40,000 nT 31,000 nT

Trinidad 10°N 61°W 14°W 34° 34,000 nT 28,000 nT

Colombia 5°N 73°W 6°W 31° 33,000 nT 28,000 nT

Azerbaijan 40°N 50°E 5°E 58° 49,000 nT 26,000 nT

USA – Gulf Coast 28°N 88°W 0° 59° 48,000 nT 25,000 nT

Bolivia 17°S 62°W 9°W -11° 24,000 nT 23,000 nT

Argentina – Austral 54°S 66°W 12°E -50° 32,000 nT 21,000 nT

UK – Wytch Farm 50°N 2°W 4°W 65° 48,000 nT 20,000 nT

UK – Central N. Sea 57°N 1°E 4°W 71° 50,000 nT 17,000 nT

Canada – Alberta 55°N 114°W 20°E 77° 59,000 nT 13,000 nT

Norwegian Sea 65°N 7°E 2°W 75° 52,000 nT 13,000 nT

USA – Alaska 70°N 147°W 29°E 81° 57,000 nT 9,000 nT

0)+

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Table 3.2

The magnetic field insome of BP Amoco’soperating areas(approximate valuesas of 1 July 1999)



01 &! /2!.

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-3.0

0.05

0.1

0.15

0.2

0.4

0.35

0.3

0.25

0

x

-2 σ +2 σ-1 σ +1 σ

95.4%confidence

interval

68.3%confidence

interval

-2.0 -1.5-2.5 -1.0 -0.5 0.0 +0.5 +1.0 +1.5 +2.0 +2.5 +3.0

f(x)

LBT " " # % 3 A $ & 1"? $ # % 5 "$T# 5 &BT" $ $ &' #% 3 7G>A$ K LBT "! 3 5 &+ " " =

confidencelevel

standarddeviations

confidencelevel

standarddeviations

confidencelevel

standarddeviations

25% ± 0.32 80% ± 1.28 95% ± 1.96

50% ± 0.68 85% ± 1.44 98% ± 2.33

75% ± 1.15 90% ± 1.65 99% ± 2.58

Figure 3.8

The one dimensionalnormal distribution

Table 3.3

Confidence intervalsfor the onedimensional normaldistribution



(%)

9$?&L "# ; $ % $ "" # &$ " % # $" $ &' "$% " . * &

North

East

% # # " 5 & ' # # &1 # 5 # 3$ " $ ,$ " &1# "#$"$&

Figure 3.9

A two dimensionaldistribution resolved

in two directions



directionof maximum

variation

directionof minimumvariation

σmin

σmax

standarderrorellipse

North

East

90

' # " % " # " & 9 " # %# "& 9 %"$""$"" " & 9 5 % A&B $ % # 5 3 A&Bσmax

A&Bσmin % LBT " $ " &+ =

confidencelevel

standarddeviations

confidencelevel

standarddeviations

confidencelevel

standarddeviations

25% 0.76 75% 1.67 95% 2.45

39.3% 1.00 86.5% 2.00 98.9% 3.00

50% 1.18 90% 2.15 99% 3.03

Figure 3.10

Principal directionsand the standarderror ellipse

Section A.2includes more detailson the mathematics ofposition uncertainty,including how tocalculate other valuesfor Table 3.4.

Table 3.4

Confidenceintervals for the twodimensional normaldistribution



4 "(

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• $ 3

• "" ρ,%ρA ρ?$ # % #% "

1 "" ! : # !"" # #&1" =

PropagationMode

ρ1 ρ2 ρ3 mean

Random 0 0 0 0 Systematic 1 0 0 0 Per-Well 1 1 0 0 Global 1 1 1 0 Bias 1 1 1 ≠0

" # " $" $" #"" &

Table 3.5

Error termpropagation modes

Appendix Bcontains a list of thecurrent BP Amocoapproved errormodels.



&"

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• " : $$ $ "

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Section A.2describes the

interpretation andmanipulation of

position covariancematrices.


September 1999 Issue 1 Theory 3-29/30

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• * #

• ! $ # $$ $

• + $ %$ "$#

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September 1999 Issue 1 Methods 4-i

Section 4

1

Contents

Page

4 13#)" 4-1

4 ") 4-6

4 &9*))" 4-17

44 &9# 4-27

4: 4-34

4; & 4-39

4< *' 4-40

4= +*' 4-48

4> 1' 4-55

4? &)# 4-59

Figure

4.1 A well planned development 4-3

4.2 A poorl y planned development 4-5

4.3 Flowchart for surve y program design 4-7

4.4 Schematic of a relief well 4-10


4-ii Methods September 1999 Issue 1

Section 4

1

Contents (cont’d)

Figure Page

4.5 The minimum separation rule for major risk wells 4-18

4.6 How a nearb y offset well appears on a travelling c ylinder 4-27

4.7 Travelling c ylinder co-ordinates 4-29

4.8 Rules and conventions for drafting tolerance lines 4-30

4.9 Principle of single wire magnetic ranging 4-32

4.10 Calculation of the driller’s target 4-35

4.11 Calculation of the driller’s target (contd.) 4-36

4.12 Effect of hole angle on size of driller’s target (side-on vie w) 4-37

4.13 Driller’s target volume for a horizontal well 4-38

4.14 Pinched-out driller’s target – a case for geosteering 4-39

4.15 In-hole referencing – section drilled with multiple BH As 4-42

4.16 In-hole referencing – section drilled with single BHA 4-45

4.17 The IIFR principle 4-48

4.18 Typical process sequence in an IIFR operation 4-51

4.19 Typical data flow in an IIFR operation 4-54

4.20 Estimating magnetic axial interference 4-56

4.21 The principle of simple axial interference corrections 4-57

4.22 A Surve y T-Plot 4-60


September 1999 Issue 1 Methods 4-iii/iv

Section 4

1

Contents (cont’d)

Table Page

4.1 Required competencies for anti-collision work 4-19

4.2 Calculation of in-hole reference corrections –section drilled with multiple BH As 4-44

4.3 Calculation of in-hole reference corrections –section drilled with a single BHA 4-46

4.4 Maximum acceptable axial magnetic interferencecorrections, b y region 4-58

4.5 Forbidden hole directions for axial magnetic interferencecorrections 4-58

4.6 Rules-of-thumb when using the error ellipse method 4-61

4.7 Quantitati ve interpretation of the error ellipse method 4-62

4.8 Example of a Relative Instrument Performanceanalysis for azimuth differences 4-64

4.9 Rules-of-thumb for use with Relative InstrumentPerformance anal yses 4-65


September 1999 Issue 1 Methods 4-1

4 1 Mathematical, logical and proceduraltools for optimum well positioning.

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1


4-2 Methods September 1999 Issue 1

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Slot in use or planned for use

Spare slot

Well location at fixed depth(say 500 ft bMSL)

Drilled well path

Planned well path

A-1

A-2

A-3A-4

A-5

A-6

A-8

A-7

A-9

Figure 4.1

A well planneddevelopment



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slot in use or planned for use

spare slot

well location at fixed depth(say 500 ft bMSL)

drilled well path

planned well path

A-1A-5

A-4

A-3

A-2

1$ $#%$ # $ 3" " #& % $ " $ ""& ) " % "" &

#+%"

+ # # "" % $*$%) "# &

Figure 4.2

A poorly planneddevelopment



It may be necessary to incur extra cost to avoid the paths ofwells that have yet to be drilled, or to survey the top-holesections of wells more accurately than would be needed werethe well being drilled in isolation.

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B& &

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Appendix Ccontains a Survey

Program Data Sheet,useful for inclusion in

the drilling program



' $ $ $ F+4 5 # " # $&

"

1 " $ $ 7" 8 % % 8 # !&9$&? # &

identify geological objectivestarget tolerances while drillingmaximum uncertainty ofdefinitive survey

selectsurvey

sequence

identify drilling objectivesanti-collision, economic target sizeexternal magnetic interferencerelief well contingencyregulatory requirements

approvederror models

checkobjectives are met

check operationalimpact / economicsadherence to “lessons learned”survey equipment suitabilityfor well conditionssurvey equipment availabilityimpact on drilling process(stationary pipe etc.)best use made of market placeminimum cost solution

check programrobustnesssufficient data redundancycontingency for tool failure

record indrilling

program

well trajectory,casing program

specify programdetailsstation intervalsminimum depth rangesvalidation surveyscontingency surveys

standardrunning

procedures

JORPs arecovered inSection 5.10

Figure 4.3

Flowchart for surveyprogram design



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• ' # " "

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. # " # % $ $ =

,& 1" " $ ## &#% "" #% # #$# &' %# $ " $ &' "$# " $ # " # & ' " $ " $ " "##" $ #&

A& " $ " $ ##55 &1# " # & 1# 3 " " #&

?& 1"## 7 ! : " $ $ ""# $ & ' % # $ # $% # # # $$ : # # $ $$ " $ #:# "&15$" " % %" " % $ 5 $ $ ," ? &



& 1 " " $ # $ " % # "" ;& 1 # # " 5 5 " & $ " &

last casing shoeabove reservoir

first approach- above lastcasing shoe

second approach- at kill point

“cone of uncertainty”around target well

Relief well

Target w

ell

B& 1 "## # &'" $ #% # $ # #$$& '" # # % " 3 " % " # # % % &

Figure 4.4

Schematic of arelief well



3 .."$$,,0* 8(* 1 ,

1 "#$ # 5 " " 3 " # $ & 1 $ " # $ 3 #&) % )1 "8 " &1 " # 5 #&

,& 9 # $;% $ " $ ? ," A & 1 "=

2σ Absolute Uncertainty = √ [ (2σ surface uncertainty)²

+ (2σ surface-to-seabed uncertainty)²

+(2σ lateral wellbore uncertainty)² ]

Example: Offshore well in 800m of water.2σ surface uncertainty = 5m (typical of DGPS)2σ surface-to-seabed unc. = 8m*2σ lateral wellbore unc. = 10m2σ Absolute Uncertainty = √[ 5² + 8² + 10² ] = 13.7m

* See Section 3.1 for a discussion of USBL acoustic position uncertainty.

Land and hydrographic surveyors will usually quote uncertainties at 2standard deviations (2σ) by default. Check. In some high step-outdevelopment wells, the above criterion may not be practically achievable. Adispensation may be justified on several grounds:

• Knowledge and/or depletion of the reservoir makes a blowout veryunlikely

• Wellbore uncertainty is substantially less in the high-side direction thatin the lateral direction (this fact could be used by careful planning of therelief well)

• The type of survey data to be acquired is amenable to further processingand accuracy improvement, should it be necessary. IIFR is an example

• There is no practical means of improving the accuracy of the surveyprogram



A& ' # $ ;% $3 $ 3"; & 1 $0) % $ $ $ # $ &

Camera-based magnetic surveys are not adequate for this purpose, exceptover short depth intervals (c. 300m or 1000ft).

?& 9""#"" $% " ; "" # " "5& 1 "" 3 ,&' "" ; " " # # $ 3 5&

There are a number of ways in which limits on the departure from verticalitymay be determined. Measuring the well inclination in the water column,probably with MWD, is among the simplest. Use of LBL acoustics isprobably the most accurate (but also the most expensive).

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0$ $ $ " & ' $% " =

,& 1$$ "& 1 "# $ & 3 ""$&C " &

A& $ ""& $ "% $ " "$ $ $&L&

LBL acousticsare described in

Section 3.1



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,& " $ " 5 $ #

,%XN $ # "& #5" """ #&

A& $ % d% # #%

" "" #%S1(di)S2(di),…SN(di).

?& %d% 4 " $$ $=

( )( ) ( ) ( )

S dS d S d S d

equiv i

i i N i

= + + +

−1 1 1

12

22 2

1

2

...

This formula is based on the simplistic but useful assumptions that (a) theinterfering field from each casing string is equal in intensity (b) the intensitydecreases with the square of the distance from the casing.

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*

1 " $# "8 "$" $ &1 $ & 1 " " 3 F+4 $$ % "" &

1 #" "3 $ " " "" & ' % " %# " % # " "" " #&' " $$ =

the amount of corroborative data in the form of check shots,multiple probe runs and the like must be sufficient at everystage to confirm the performance of each instrument run inthe hole.

The preciseinterpretation of this

rule for MWD surveysis described in

Section 5.2



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#

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&

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lesser of :a) 1% of drilled depthb) 10m

radius ofinterfering well

radius ofplanned well

most likely positionof planned well3 σ error ellipse

3 σ error ellipse

most likely positionof interfering well

MINIMUM ALLOWABLE SEPARATION

Figure 4.5

The minimumseparation rule for

major risk wells



A& 0 :04)

1 ( $ $ " $ % " #& 1 # 4 # " "$ % $ $ 14"#&

0*A)

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Specifically, the following personnel must have been assessed by a directionalspecialist as competent in the following skills:

Performinganti-collisioncalculations

Draftinganti-collisiondiagrams

Using the anti-collisiondiagram for decisionmaking while drilling

Well Planners

Person responsiblefor ‘signing-off’ wellsitedrawings

Directional Drillers andDD Co-ordinators

BPA Personresponsible for‘drill ahead’ decisions

)# " % ## # &

$ # # $&

" # 3 M 4 M4 " $"" 216&

Table 4.1

Requiredcompetencies foranti-collision work



'

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1 # " " # " # # " 8 &

1" # ""$ # &

&

# " # 8 # " $ " "&

For a database to be used for the definitive clearance scan, there must be aprocess in place which ensures that it is, for practical purposes, identical to thedefinitive drilling database. It need only contain a subset of the wells in thedefinitive database, but must at least contain all the wells known to have beendrilled in the area of interest.

1))#&

1# "## $ $ $#&

The separations are considered as distances measured perpendicular to theplanned well, so that they lie in the plane of the anti-collision diagram. ‘3D’ or‘minimum distance’ separations are more conservative, but cannot beadequately represented on the travelling cylinder plot and are therefore not partof the Recommended Practice.



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* # # " $ 080&

1 " # "#$ " " =

A nearby well presents a$ )if a collision with it wouldcarry a significant risk to personnel or the environment. Itpresents a ) if the risk to personnel and theenvironment in the event of a collision would be negligible.

The Major/Minor risk classification is preferable to the more prescriptiveFlowing/Shut-in classification because it forces the engineer to think throughthe implications of collision in differing situations. For example, theconsequences of collision with an oil-producer just above a shut-in SSSVshould certainly be subject to a thorough risk assessment before the well isclassified as Minor risk. Conversely, a collision with the same well in theperforated part of the reservoir section might well justify the Minor riskclassification. Used in this sense, ‘Minor’ is a relative term – a well may beclassified as Minor risk without implying that a collision with it would be of minorimportance.

) " $ # $ " #% "$# &

A well may present a Major risk for only a part of its length. For example, belowthe shut-in point, or more than a certain distance above the reservoir.Calculations involving the mud weight, shut-in pressure and fracture gradientmay be required to establish at which depth the risk classification changes.

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## $ %" $ &



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#

σ, K # ,

&

σA K ' "$ # ,

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Example: Planned well uncertainty at 1 std. dev. = σ1 = 8 mInterfering well uncertainty at 1 std. dev. = σ2 = 5.5 mHole size in planned well = d1 = 17.5" = 0.445 mCasing OD in interfering well = d2 = 13.375" = 0.340 mAllowance for survey bias = Sb = 0 mDrilled depth = DD = 650 m

Separation = 3(8+5.5) + H(0.445+0.340) + 0 + 0.01(650) = 47.4 m

Section A.5explains how relative

surface positionuncertainty is included

in the minimumseparation equation

Section A.5explains how survey

bias is included in theminimum separation

equation



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1# # "=

K ( )σσ π

22

1

21 2

1 2lnd d

Rd d Sb

+

+ + +

#=

σ K σ σ12

22+

R K 14

Example: σ1, σ2, d1, d2, Sb as aboveTolerable Collision Risk = R = 1 in 80 = 0.0125

σ = √ [8² + 5.5²] = 9.71 mSeparation = 9.71√ 2 ln [ (0.445+0.340) / [(0.0125)(9.71)(2.51)] ]

+H(0.445+0.340) + 0 = 13.8 m

The risk-based separation equation exhibits some unexpected behaviour.In particular, it is meaningless when

d d

R1 2

21

+<

σ π

This occurs when the relative position uncertainty of the planned and interferingwells is so large that the tolerable collision risk cannot be exceeded even if theplanned well is drilled straight at the interfering well. The minimum separation Inthis case can be set to zero and no-go lines need not be drawn.

1 1 4 14 # " " 3 " " $ # 2 &

For convenience, a risk level may be used which is less than the valuedetermined from the cost-benefit analysis. Thus, for example, directionalsoftware might present a pick-list of rules based on risks of 1/10, 1/20, 1/50,1/100, 1/200 and 1/500. A calculated TCR of 1/57 would indicate that the 1/100risk-based rule should be applied.

For more onthe behaviour of therisk-based separationequation, and itsderivation, see A.5.

Section 4.4gives guidance ondetermining TolerableCollision Risk



1,1(1 "*$,9 *&C3 ..

9 #% : " " ## : # $ #&

Even when this is done, it is sometimes impractical to apply the standardminimum separations rules immediately below the kick-off point. In this case,good judgement must be used to determine from what depth the standard rulesshould be enforced.

&)

$ # $ $ # & ' 5 % # $ 3 "% #> &

It is occasionally possible to represent drilling tolerance lines adequately on planview or vertical section plots, eliminating the need for an anti-collision diagram.For example, where there is no interference near surface, a single interferingwell is involved, and the interfering well remains either above, below, or to theleft or right of the planned well. Where there is any doubt that the drillingtolerances can be represented accurately, clearly and unequivocally in this way,an anti-collision diagram must be used.

1 $ # " # # . $ ,AV &

1 # # $ # " # # &

Use common sense when it is clear that a particular no-go line cannot beviolated due to the presence of other, shallower drilling tolerances.



&3

* $# $ $&

$ # $ # #" 3" &

Where the only deviations from the survey program are altered start and enddepths to survey sections, it will usually be sufficient to recalculate theuncertainty in the planned well and to decide if the consequent changes inposition uncertainty are significant. Eliminating surveys from the program,changing instrument types, or radically changing depth intervals will alwaysrequire a full rework of the anti-collision calculations.

# > F + $4 $F+4B&,&

" % " ## $&

,+*,0 1 ,$+$. *,& .,

) "" # # &

' " $ % $ # $ % $ # "" ""&

When a tolerance line has been crossed, or is likely to be crossed if drillingcontinues, the situation must be assessed by the onshore drilling team. Firstly,the anti-collision diagram must be examined to confirm whether

either the tolerance can be relaxed without violating any no-go areas (forexample if the line has been drawn to smoothly join two no-go areas),

or the tolerance line protects only planned well(s) and there is sufficientroom to safely re-plan these at a later date.

In either case, an amendment to the anti-collision diagram with the tolerance linemoved to allow drilling ahead can be prepared. If only a small section of thediagram is affected, it may be faxed to the rig.



It is always better to provide the rig with a revision to the anti-collision diagramthan with verbal or written instructions. It will usually only be possible to relax atolerance line by a limited amount, over a limited extent of the diagram. Thisinformation is difficult to convey in words.

If the tolerance line protects an existing well, the options to be examined include:

• Plug back and side-track

• Re-survey with a more accurate tool

• Perform a QRA analysis to justify drilling ahead

• Drill ahead with increased survey frequency and alertness (this may beappropriate where a tolerance line is just being ‘grazed’)



44 &9#

&

11$ 8 "&1 8 "% # """ #& 1"#$$##"" # =

20’40’

60’80’

992’

20’

20’

40’

40’

60’

0’

40’

1976’20’ 40’

planned wellinterfering well

N

S E

W0

180

270 901000’

2000’

4000’

20’40’ 60’

80’3000’

20’2910’

3826’

4779’5000’

4779’

992’2910’

3826’1976’

* + * ,& (* /

' $ # 8 & 1 " $ $ $&" # # 8 &

For moreinformation on theTravelling Cylinderand its uses, see

!" ! #$

%

!

&

#

Figure 4.6

How a nearby offsetwell appears on atravelling cylinder




* + * ,& * &$,

' $ % #; # $ & 1 #. " $% 7 . !& " # # # $ ,A! &

1 $ " #$ # $" $$% " & 1 " . " 8 ## %# $ #$ "5 # $$ # " #& 1 $ " "$# $% # #$ " 3 &

* ..,0&/., *&$$*,

$ " # & 1 " " $& % " # & 1 %# $ $&% $#" # $ # ; &) # % % $ $ $ " #&

$ $# $ # 1 # # " $$ & 2" " # &' % % " $#" &




2347

2370

Relative Bearing = 96 deg

Radial Distance= 31 m

RelativeDepths

50

40

30

320

300

Interfering Well

,$0$* ,$. *,& .,

1 $" $$ 8 ! $ & "" #% ## # $ "& $ $ # # % % %#$ &

#$$ "" # $ # 3 " & 9 % ## " 7$!& ' $% $ $ $ &1 # &

Figure 4.7

Travelling cylinderco-ordinates

For a step-by-step guide to drawingtolerance lines andcompleting anti-collision diagrams,see'( (

)&

$ * by HughWilliamson, UTG WellIntegrity Team



*+,0$. *,& .,

1 "#$ "$ # " "$$# &

800

960

900

980

1000

800900

1000

1000

1000

800

Here, there is room to cross the 800 ft linebefore reaching 1000 ft, whilst staying outsidethe minimum tolerable separation. Separate tolerance lines have therefore been drawn.

A separate 800 ft tolerance linehere would be pointless. It could

scarcely be crossed without drillingwithin the minimum tolerableseparation at a greater depth.

Entering this area would violate the minimumtolerable separation at 990 ft, even though

the no-go area has not been plotted

&*

1 14 " # # " ##& ' 5 " " & # $ " " # &

1" "=

1 " 3"C ) &

1 " $ $

V ) &

1" M4$ &

. &

Figure 4.8

Rules andconventions for

drafting tolerancelines

The worksheet,plus 3 completed

examples, is inAppendix C.



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" % " M

F $ # " # "#$ &

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• 1 " "$ # % # 8 % $$ &

• 1 " "@%#"$% &

• 1 ""$ "3 "5 #

1 # $ $ " $ $ % $ % & ' # $$ &15 5 "#" $ " " 3 &&



5 ) - $

) & 1 " #$ " "% " "M4 # " & ) #$ " $" " 3&

31*

)04 3 $ " $ ""#%# "&' @ 0$ '& " ' % .# U&1 2 B%EB%ELS B%B,B%L?,B%-BC%EA-&*5$ " $# > &

"*,&".

$ " # $ $ # #& 1" 0) $ #& # 0) "$ ""& " #&

eletromagneticfield lines

well to beavoided

wire insidewell carrying

current I

conductorelectricallygrounded

wr

B

MWDsensors

well beingdrilled

For more on thepractical limitations of

QRA applied toanti-collision see

+, ,

!( & -&.)

/&

0 -&

For moreinformation see

++

&

# 1&$

$

$ -$$

!"2

3

&.

Figure 4.9

Principle of singlewire magnetic ranging



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"5 "$ # " #0)% # $ # & ""$ $ $ " # * ! $ " "

%$8 "%B, #& 1 " % r % " 0) "$

#% ! 6#% ( )Br

r w= ×µ

π0

22

I # w

"$#& 1 r $ 8 " 3 =

( )rB

w B= ×µπ

022

I &

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)04 # # $ # # &' "" # "$# # # " # 8 & # "$# $$" 3 " " $ &



1$" % # 5# " % " 0) & ) %

,A % "± " , " ±,B" A " 5 % # 5 $ " AB" &

' $ 21/ $#" &

4:

1 % $$8 "#" ""# &' "% " 3 # # " $ & " %# ,T $$ 8 &)"

'$ " $&

' $ $ ! &

* " & # $ " 5 $ "$ & # 3 $ & 1 # $ $ $$ & 4 " $3 &



5

1 " $$ $ # # "" " 6 &'"$&, # $$ $ #& / %, " # $ #"$&,&

geological target

surveyedwell path

2 s.d. error ellipse

(a) (b)

apparent pointof penetration

*$ " , # # "$ $$ $ & ) $ " $$ $ " LAT& $ $$ $ $ $ &,,&

Figure 4.10

Calculation of thedriller’s target



> 95%90% - 95%

< 90%

welldirection

(c) (d) geological target

driller’s target at95% confidence

inclusion probability

9% # " " $$ $ # # % % LBT% 7! $ LBT"!&1# &,,% $ &

'&'.

1$$# 2 $$ $ ! $ % " $ & ' % " $$ $ % ! $ " $ " $ LLT%# $ $"" & 9 $$ $ % 5 #% ; $ #% & #% "$ ;" ! $ $ "#$=

5 $ $$ $ # $$ &

* $ &

$ # " $&

Figure 4.11

Calculation of thedriller’s target (contd.)



$"" $ # $$ &

""LBTLT " 3& ! $ " LT" 5 &'5 % " # 3 &

'''##

1 ;" ! $ 7 !#! " $$ $ & 0 $ " ; " # # %#" $& 5 % ; $ # ; #&

highsideuncertainty

Low angle well

(1) uncertainty is magnifiedby foreshortening

highsideuncertainty

High angle well

(2) target is truncated at near andfar edge by magnified uncertainty geological target

driller’s target

# %" $$ $ " $ $"$ "" " $ $ & 1 5 % "" =

amount of target truncated at front & back

= highside uncertainty / cos (incl)

9 3 # % #$! $ LET"&

Figure 4.12

Effect of holeangle on size ofdriller’s target(side-on view)



&'5

0 $ # " #& $ " # " " $ " $ &

% ! $ # " $ & 1 $ 3 &

'D3

" " $"" # $ $$% $ " ; # " ; & 1 " $$ $ "" & 1 " % 5 % 1 " #& ! $ " % 8%"$! $ #&

entry plane

exit (or TD)plane

geological target volumedriller’s target volume

directionof well

'" $ $% "" ! $ 7 !&% # #& 1 $$ $ $& ' 8 $ $&

The BP Amocoalgorithm and thegraphical method

are described inSection A.4

Figure 4.13

Driller’s target volumefor a horizontal well



geological target volume“pinched-out” driller’s target

directionof well

4; &

1 5 $ "# " $# . %* %1@%" % %; &13 " " 5 $" % # $ % $ $ 5% # $ ' & 1 " % # $ # &

' " # & 7 " !% 7$$!7 $ ! " % % $& 1 % 8 # $ " # $ % "# # &

Figure 4.14

Pinched-out driller’starget – a case forgeosteering

The minimumcurvature equationsare given inSection A.1




*&

1 " $$ % ; " # % & ' %## 8 " & 2" % " 3 % & %#$ $" % &,&

4< *'

' "$ '4 $ 3 $ # " 8 0) & ' $ & $ % 5 . &

"#'*

' "$# $ "0)$ " % $ ; # 3 # 0)& 1 #8 " 0) ; :$ 5 $ " : $ $ ! $& 0) " # # # 0)> &



## '*

' "$ #

• 1 #$ A°

• ; A" # $ # '4 :#

• 1 $ ; 5 705$ !#

# -

' %0) " $ # $ # $ &

' "$ $ 0) & ' %# &

)#&

' "$ 8 $ & ' ! $ 3 $ : " & $ " # $ # # # " # 0) &

It is vital that all IHR corrections are checked forreasonableness as well as numerical accuracy, and thatunusually large or highly correlated corrections areinvestigated by a survey specialist.

Survey datacomparison isdescribed inSection 4.10



*"

1 # $ # & ) " $ # $ % " # "# &

gyro multishotsurvey

in-hole referenceinterval

IHR MWD surveys

MWD surveys

BHA #1

BHA #3

BHA #2 BHA #1

BHA #3

BHA #2

,& # B " ,B , " ? " $ # $ & 1 $ # #5 " $ " #&) % # $A" 3 & 10) " $ # $ # $&

Figure 4.15

In-hole referencing –section drilled with

multiple BHAs



A& $$ 1" & 1 3 # $ "$ $ $ "$ $ & AB" , &1 &

?& + #

"# &1 =

" $ # $ "" " $ "&AB" CB&

A" -$ &

# ; " &B° # &

1 > '4 % 705 $ !#&

& " % # $ % 0) # '4 & 1# %# "$ # "

L°% $ ; &

"" '4 &1 &1 " $% "0) 5 "$ &

B& ; # 3 0)> # $ &



&.&(.$,$+*&$** &$,9

1(.". -

) $ % '4 " $ $0) ; # "; &1"#$ 5 =

MeasuredDepth

GyroAzimuth

MWDAzimuth

BHA # InterpolatedGyro

Azimuth

IHRCorrection

CorrectedMWD

Azimuth1250 271.62°1275 271.81°1300 271.77°1325 272.04°1350 272.16°

1315* 272.7° 1 271.93° -0.77° 271.93°1413 273.6° 1 -0.77° 272.83°1508 274.1° 1 -0.77° 273.33°1604 274.3° 1 -0.77° 273.53°1255* 272.1° 2 271.66° -0.44° 271.66°1699 274.2° 2 -0.44° 273.76°1793 274.7° 2 -0.44° 274.26°1300* 272.9° 3 271.77° -1.13° 271.77°1886 276.1° 3 -1.13° 274.97°1980 276.2° 3 -1.13° 275.07°2073 276.5° 3 -1.13° 275.37°

* In-hole reference station

* *$" & &$** &$,$+13(* /

' ; # '4 &'" 0) # '4 % ; " $"$ " &

Table 4.2

Calculation of in-holereference corrections– section drilled with

multiple BHAs



1$+ "*$& (* +$*,0. - &$,

) $ ## $%5 '4 =

gyro multishotsurvey

MWD surveys usedfor calculating IHR

correction

IHR correctedMWD surveys

MWD surveysrejected due to

external magneticinterference

,& ' " $ A" % '4 " 0) & 1 "#$0) 5" =

• 0) # # " 5 $ " 5 $

• 0) # "

5 $; J&B° #

• 0) # '4 #3"" $

Figure 4.16

In-hole referencing –section drilled withsingle BHA



A& 1" " $ $ 0) % $ &

?& 1 # &

& " % '4 "#$ &

1"#$ ##$'4 =

MeasuredDepth

GyroAzimuth

MWDAzimuth

Interp.Gyro

Azimuth

AzimuthDiff.

IHRCorrection

CorrectedMWD

Azimuth6200* 83.23°6300 83.06°6400 82.69°6500 82.24°6600 82.38°6700 81.60°6800 81.45°

6276 82.1° 83.10° 1.00°6370 81.6° 82.80° 1.20°6467 81.3° 82.39° 1.09°6562 82.2° 82.33° 0.13° reject †6655 81.1° 81.95° 0.85° reject ‡6749 80.7° 81.53° 0.83°

mean +1.03°6842 79.9° +1.03° 80.93°6936 79.1° +1.03° 80.13°7030 77.9° +1.03° 78.93°7125 78.0° +1.03° 79.03°

* For illustration only – reference survey interval should be 25 ft or10 m.† Rejected – statistical outlier.‡ Rejected – azimuth change between reference survey stations>0.5° (Azimuth change between 6600 ft and 6700 ft = 81.60° –82.38° = -0.78°).

Table 4.3

Calculation of in-holereference corrections

– section drilled with asingle BHA



121(1&,0 ,$. * &$,

'"$ ; "" $0) $ & 1 " $ % " 5 $ " $ $&15 $ & 1 "#$ " $ $ $"0) " &L" =

Max. change in sin(Inclination)sin(magnetic Azimuth) ≤ ±0.25

Example A proposed IHR section starts at 65° inclination, 150° magneticazimuth, and finishes at 75° inclination, 130° magnetic azimuth.

Is this change in hole direction acceptable ?

Answer sin(65°)sin(150°) - sin(75°)sin(130°) = 0.45 - 0.74 = 0.29

The change in hole direction is too great, and IHR cannot be applied over thewhole section.

,$. * + * ,&,0$+ . &*$,&1(.$

* " # 0) # $ & ; " # "%" 5 $5 $ " &



4= +*'

$ 3 " "$ & $ $ % 3 " $ $ " $ & . "$" $$ " /$ //$ 0 //0& #% $ $ " " & 1 " " "" # $$ "?&A&

'% $ # $ " $ " # $ & 1 & 1 3 " " "$ ''94 5 & ''94 "" " $$ " # $ " $ "&'"" 7 !$ % $ $ " $ 3 &

Observatory

Measured Fieldat Observatory

Calculated Fieldat Wellsite

Mean Offset DerivedFrom Wellsite Survey

Wellsite

For a completediscussion of

interpolation in-fieldreferencing, see +, -

)/

&

1

!" $"

00

4(

5*$ )

6 - $

!"2 and ,

00

0 )

6 - $

-*

7&"

8&

Figure 4.17

The IIFR principle



1+1

+% 7 !" $ " $ 3:3 # % $ $ 3&+""% %$ "& 1 " $ 3"$ 5 &

1$ " "$ "$ # " $ & 1 " $ " " $ & " " %" $$$$ "& 1$$ "" & 1 " " " $ " "&1 # $=

1 " & 1 " " " $ &

1 ; "&$ """# #" % 5 $; "&

1 # $ B B &



1$ # 5 " $$ " " " $" #$ &)5 %5 $ " " $" &

+*'$#

'94 & ' 3 " $3 %$ " 5 #$ ""& 1 $$5 &

.$,$+10, &+ ..(

$ " " " " % 3 & 1 $''94 0)# $ $# $ & 1 %"# $"" =

• 4 $ " # # " $ $5

• '" $ #% " 0) %

• ''94 0) ; # "0); &C

"".&$,$++*

% " ''94 3 &1$ $ " &1 # " ''94 #3&



!

Real time(rig site)

Regularturn-around

(office)

D#$" " # #& 9 % " $ $&1 "% $ " ##% "5 #" 8 "& % " " $ $ # $ 3 $&

0)3 $ " $ % &* $ # $ & *5 $ $ % $ % G>, "" % 0)>$$ $& 9 3 55 $ " " $ 5 " 3&

Figure 4.18

Typical processsequence in an IIFRoperation



$"$,+$*"*$& ,0

1 " $ " $ # # ''94&1 $ 3 5 &1 "" "$ % 5 " $ $ 5 & 1 % # # = " $ $ % " " " # & 1 "; "#&

OPTION 1 Correction for crustal field declination 1$ " $ " " $ ; & % #3$ " & $ "& 1 $ & "" # " " %$ 3 " &

OPTION 2 Correction for crustal field declination anddrillstring interference

"5$ "$ "$ " $ " $ &1 # " $ $ " # " &+ # "#$"; # 5& * " $ " $ $ + , "#&



OPTION 3 Correction for tool sensor errors, field variationand interference using near real-time data

1 "" " B&A # " # 5 "$ " " $ "& / $% " % """ ""# $ &

+* 8( ,&/$+ . */

1 "3" $ 3 #=

• D $ $ " " #

• $ " " # "" $

• 0$

$ " $ % " 3 % " # " " & ' " $ $ % ##$ " # % #3 "# &'" " $''94 " " # % " $% $ $ &

0 $$ $ " &1# # $ &



*& 1,0 1 ,,&$11(,&$,

3 " ''94 "$ & 1 % $ % 0) " $ & 4 $ &1" "53 5 &

PermanentMagnetic

ObservatoryLogging

UnitDirectional

Engineer’s Office

GeomagneticData Centre

IIFR DataProcessing Office

ObservatoryData (real-time)

Observatory Data (bulk)

IIFR ProcessedMWD surveys

RAW MWDsensor data

$3, *"," ,*0

1 " 7 $ ! # % 8 1$ 2D . * 4 /$ )+LC,,?& ) $ $ " % / # $ " " &

1 "$ " $ " % $"$ " $ & ' ""$" # "21/&

Figure 4.19

Typical data flow in anIIFR operation



4> 1'

0$ " " $ ""$ &' # =

• $ $5" % $ & " $ "5

• 0 $ $ $5" & ' "" " #7!

!'

1 " 5 " $ ' "% " &

-& $*/

0$ $ $ % # $

& 1" %B%

" " $ %P% ! %z:

BP

zm =4 2π

Bm1K,1%z %

")µ)& $ "

µ)% ,&& " " & ' 5&



1 5 "$ "% % " " "" " &9$ &A # # # " # "$ &' " # & 0$ % $ # &

z1 z2

P1 P2

Drill Collar Mud Motor BP

z

P

zax = +

1

41

12

2

22π

z1

z2

P1 P4

Drill Collar Mud Motor BP

z

P

z

P

z

P

zax = + + +

1

41

12

2

22

3

32

4

42π

Stab.

z3 z4

P3P2

magneticsensors

magneticsensors

1"&$,- 0,

1; %∆az%5$ " 5" " % % $ " " "$"&) "$"# ; " * ! "% "#$ 5 " 5 =

( ) ( )∆azax

H

B

BInc Azi=

180

π. .sin .sin

# BH ; $ " $

?&A " 5 % Inc Azi $ ; &

'$%$

"5 " $ &B°& 1# " $ $ ,&&

Figure 4.20

Estimating magneticaxial interference



2., *+ * ,& &$** &$,

$ # " 5 " " & 1 # "$&A,=

magnetic north(direction relative todrillstring unknown)

B

apparentmagnetic

northaxial

interferencevector

(magnitudeunknown)

Bax

B + Bax

Problem

(3) and we know the Earth’s field vector is this long:

(2) and we know the interference vector acts in this direction

(4) so we can work out that magnetic north is in this direction

B + Bax

(1) we can measure this vector

Solution

1 "$ $$ "#$ " =

• 1 #$ " * !$ "& ) &""$ "% # $

• 1 " 5 "5 "&L

• . " $ " * ! " " "&2" % # "" "5 " # : # # ; $ #

Figure 4.21

The principle ofsimple axialinterferencecorrections



• " % "#$ #$ =

• $ # & 1 " $ & 6 $ "55 $ "

Drilling Area MaximumAcceptableCorrection

Gulf Coast, Middle East, Far East, Africa, South America, FSU 6° North Sea, Northern Europe, Canada, Norway 8° Alaska 10°

• # ,? " "$ $ & ) %5 " &

• 5$ " # " 5&LB& 1 "#$ " " =

Azimuth of Well Forbidden Inclination Range

Magnetic E or W ± 19° or more no restriction

Magnetic E or W ± 18° 87° – 93° Magnetic E or W ± 15° 80° – 100° Magnetic E or W ± 10° 75° – 105°

Magnetic E or W ± 5° or less 72° – 108°

'$ % " $" $&

Table 4.4

Maximum acceptableaxial magnetic

interferencecorrections, by region

Table 4.5

Forbidden holedirections for axial

magnetic interferencecorrections



1(.$,,./

8 $ # 0) # $ 5 " & 1 7 ! 3 0) & # # " $& & 1 $ " """"$# " " $&

0 " $% $ " " & 1 " $ 0)% $" " $& 1 " &

4? &)#

" $ #" $ " 3 $& 1 :1 % % #4 ' "4'&

*A)'&)#1

M 3%$ $" "" # &7$" ! " 7 !&1=

• 1 $ # $" "$ #

The developmentand validation ofINTEQ’s method isdescribed in ,

00

0) #

$

$ "*



) $" "" "% 5 % # " &1=

• 1 $ $ " %## "

. " "" 3 % " &

"

1 $ #$ " # & 1 " $ " 5=

Incl

inat

ion

Azi

mut

h

MD5

30

25

20

15

10

40

35

315

340

335

330

325

320

350

345

500 2500200015001000

MWD

Gyro

1 #" $ $ " & "" % " & 1 # $ " $ " $&

Figure 4.22

A Survey T-Plot



1 1

&,°>A°>&9 %1 EH[5,,[ " :5 $#$" " 3 &

1 ## $"" # $ # 5 $ "&13 "#$ &

#1

$" " " &* %" %" # % # # & ) 3 " !$ &

9 % # # & 1 ; % " $1@& 9 $ $ ; #% # $ &

9 $"$ >$ $=

Overlap at 1 s.d. Good agreement. No further investigationnecessary.

Overlap at 1.5 s.d. but not at 1 s.d:

Average agreement. No furtherinvestigation necessary.

Overlap at 2 s.d. but not at 1.5 s.d

Poor agreement. Recheck both surveyscarefully.

No overlap at 2 s.d. Disagreement. One or other surveyalmost certainly contains a gross error.Investigate to resolve the discrepancy.

The equations forcalculating theseellipses are inSection A.2

Table 4.6

Rules-of-thumb whenusing the error ellipsemethod



2" % " " $$ " " % >" "& 1 # 73 !& #% " " # =

• 1 # & $""

• 1 #

• 1 #

) % " # & 1 # # % "$ # % # $ &1 % $ $&. " ;" & " # " # &

Ratio (R) ofellipse sizes

R = 1

R = 3

R = 2

1 s.d. ellipses 1.5 s.d. ellipses 2 s.d. ellipses

2 %

3 %

4 %

37 %

41 %

45 %

11 %

13 %

16 %

Probability thatellipses willnot overlap

Table 4.7

Quantitativeinterpretation of theerror ellipse method



*)"')

4' " 3 " & ' ; "" # # # "" 5 " & 13" "#=

• $

• =

∗ ' "

∗ - $ " "

∗ , && " " $

∗ , && "" # " 3 "

∗ "" , &&"" $

• 9 " "" #

• 4 "; ""



MD Comparisonsurvey

azimuth

Interpolatedreference survey

azimuth

Observedazimuth

difference

1 std.dev.azimuth

difference

Normalised azimuthdifference

(ft) survey 1 s.d. survey 1 s.d. (std dev.)A B C D E = A - C F = √ B²+C² G = E / F

1349 135.7° 0.78° 136.61° 0.35° -0.91° 0.85° -1.061444 136.4° 0.78° 137.54° 0.35° -1.14° 0.85° -1.331538 136.9° 0.79° 137.81° 0.36° -0.91° 0.87° -1.051632 137.2° 0.81° 138.45° 0.37° -1.25° 0.89° -1.401727 136.9° 0.82° 138.59° 0.37° -1.69° 0.90° -1.881822 137.7° 0.82° 139.02° 0.37° -1.32° 0.90° -1.471916 138.9° 0.83° 139.66° 0.38° -0.76° 0.91° -0.832011 138.1° 0.84° 140.45° 0.38° -2.35° 0.92° -2.552106 139.5° 0.84° 140.73° 0.38° -1.23° 0.92° -1.332200 141.6° 0.84° 141.75° 0.39° -0.15° 0.93° -0.162294 141.6° 0.85° 142.18° 0.40° -0.58° 0.94° -0.622388 142.7° 0.86° 142.89° 0.40° -0.19° 0.95° -0.20

mean 1.56 s.d.std. dev. 0.65 s.d.

$ " & $ " $ % # $& $ " $ "&

Table 4.8

Example of a RelativeInstrument

Performance analysisfor azimuthdifferences


September 1999 Issue 1 Methods 4-65/66

1 "#$ % 5 % # =

Normalised Difference(Incl. or Azim) Interpretation

Mean Std. Dev.

< ± 0.5 and < 0.5 Good agreement

± 0.5 to ± 0.75 or 0.5 to 1.0 Average agreement

± 0.75 to ± 1.25 or 1.0 to 1.5 Poor agreement.

Re-check both surveys carefully

> 1.25 or > 1.5 Disagreement.

One or other survey almost certainlycontains a gross error. Investigate toresolve the discrepancy.

Table 4.9

Rules-of-thumb foruse with RelativeInstrumentPerformanceanalyses


September 1999 Issue 1 Survey Tools 5-i

Section 5

Contents

Page

5-1

5-4

5-11

! "#$%& 5-13

'#(% 5-24

) *+%#& 5-26

, - 5-28

. /%%0% 5-29

1 - 5-31

2 3+4 5-35

Figure

5.1 Sensor arrangement in G yrodata’s Wellbore Surve yor(large diameter tool) 5-15

5.2 Keeper tool configured for a 9-5/8" or 7" casing survey 5-19

5.3 The RIGS surve y probe 5-23


5-ii Survey Tools September 1999 Issue 1

Section 5

Contents (cont’d)

Table Page

5.1 Position uncertaint y for inclination onl y surve ys 5-2

5.2 Qualit y measures for electronic magneticmultishot surve ys (generic) 5-13

5.3 Qualit y measures common to all G yrodata surve ys 5-17

5.4 Qualit y measures for G yrodata g yrocompassing surve ys 5-18

5.5 Qualit y measures for G yrodata continuous surve ys 5-18

5.6 Qualit y measures for Keeper multishot surve ys 5-21

5.7 Qualit y measures for RIGS surve ys 5-24

5.8 JORPs documents currentl y in use 5-37


September 1999 Issue 1 Survey Tools 5-1

The surface and subsurfaceinstrumentation used in wellboresurveying.

Recommended Practices for tool selection and operation arein italics.

!"

"


5-2 Survey Tools September 1999 Issue 1

5--

Their use should be restricted to near-surface sections ofisolated exploration wells or well-spaced development wells.

#$

"

AverageMeasuredInclination

Position Uncertainty at 1.s.d.(ft/1000ft or m/1000m)

0° 13

0.5° 22

1° 31

1.5° 39

2° 48

2.5° 57

3° 65

" %& '( ) ) *

Inclination only sections near surface should normally beresurveyed later in the drilling operation.

" + ,-.

Table 5.1

Position uncertaintyfor inclination only

surveys



-

" " TOTCO "

6 "'7" +

TOTCO " "

" /TOTCO) 0# # "

6 "'7" +

"Teledrift 1 % /) $ #

Anderdrift

# 2

" -3° "

4°$-3° 53°$64°$



5--

" 0#'# % " " 0# %7

• 8 9 %+92%. (

• ( ( ( % 0# " $

-

% $ + . $ + ,:. "



" ' $ ;$6<-= ! $ +. '$ !,$><,=

55+5"57

% " " $ 7 ? ? < # %

" $ # % + . $ 2



% $ 0 0# "

+ '"57 "+

# % 2 2 ) ) ( 2 )

" ( " (

-

1 " ! " $$

785' 50+ "

% 0# + . " " % + 36. 0# " 0# %



The determination of this offset is a safety-critical task, andmust be checked independently before the BHA is runin hole.

% 0# % " ! 0#

& %

+ >°3°.0#

+@4°@6;4°@-54° @:4°. "

9+5:; '40 55

% ( ! "

Six-sensor ‘raw’ data should normally be transmitted tosurface, with inclination, azimuth and toolface (andassociated QA measures) being calculated from it.

<5%;%

All MWD surveys must pass a number of internal andexternal validation checks. Details are below and in JORPs.

" +"57<057=50+5"'

" /$)% 7

• A$

• $



• !

" $ % ( B#+,:.

> +"5755;575"

2( B# "

Each MWD tool must pass a comparison with external data.

" 7

CHECK SHOTS

2 0# +,%. ( ! 0# $ # 7

( 7 43°

( !7 >4°

C #

Section A.3contains details of

how to calculate these quantities



%<0# ( !7

( 7 4-3°

( !7 63°

% #

Whenever possible, MWD tools should be changed outduring bit trips.

" %

ELECTRONIC MULTISHOT

( +21.% " 0# $ % 0# 21

MULTI-STATION DATA ANALYSIS

% $ +,5. $ + ,:. ( 2($ + . %



4 "5"8+ > +"57;575"

2( % 7

• "%3° $

• "% $

5&" '0+(5"' "+"&

2 % $ 1

5

# % # $ + ,5. $ + ,;. +,:.

# !

" 0# 1 ( "'# +.



2 +21. " $ +33.

5--

21 " % 21 %% 21 ) 21

21 6444 1 +211. " %

-

21 64=-4=&" " $

two probes should be run in tandem for all EMS surveys.

21 % 1 + #1 ".



-

"

" + /TOTCO

).0##

% ) )

""#5&" '45'"&

" $

Non-magnetic spacing requirements for electronicmultishots are the same as for MWD, with the additionalrequirement that neither sensor be within 1.5 m (5 ft) of atool joint.

+5"6

D 21 " ;$64 " C E&C' +364.

MWDnon-magnetic spacing

requirements arein Section 4.9



<5

B# % 21" 7

QA measure Tolerance Failureindicates

Possible cause(s) of failure

Divergence betweenprobes – Lateral

< 5/1000 Systematicazimuth error

magnetic interference

Divergence betweenprobes – TVD

< 2/1000 Systematicinclination error

tool misalignment or BHA sag

Gravity FieldStrength (G-total)

< ±0.007g*

(all surveys)

Inclination andazimuth error

Faulty accelerometer or toolmovement

Magnetic FieldStrength (B-total)

< ±700 nT*

(all surveys)

azimuth error magnetic interference, largecrustal anomaly

Magnetic Dip Angle < ±0.7°* (all surveys)

azimuth error magnetic interference, largecrustal anomaly

* difference from modelled value

! "#$%&

* / ) " * 2 # ( % $ 2 " ("*

! 2 ) " * " 7

0! 2 C @Ω@634,6+Latitude.<

" $ 2 )

Table 5.2

Quality measures forelectronic magneticmultishot surveys(generic)



&%"#$&

A )Wellbore Surveyor +GWS. $ 54F 53F " ( " Battery/Memory +RGS-BT. "G+RGS-CT. $$ 63°

5447'5"

" Wellbore Surveyor 7

• 1

• %

"

Continuous7

• G <

• $

"Battery/Memory( 7

• 1

• + .



7 '+4"

" " H +-4 . "& --3=>H= # & 653=

accelerometer(non-rotating)

Universaljoints

exciter/pick-off coils

torquercoils

gyroscope(rotating)

magnet assemblyfor torquer coilsto force against

motor/statorand bearingassembly

" -$ ( -$ ( "

" (

Wellbore Surveyor Battery/Memory$+ ! .

Continuous + 63° . !

Figure 5.1

Sensor arrangementin Gyrodata’sWellbore Surveyor(large diameter tool)



4 +5"57 <0 "' ?'""00076

0+; =

% + ( .$ $

9 64°$63° "

#64°$63° ! "">4" C$

64°$63°

9 / ) "



4 +5"57 <0 "' ?+40+; =

% Battery/Memory ( +( $ .

" + . " < # B# (

<057=50+5"'

" 7

QA measure Tolerance Failure mayindicate

Possible cause(s) offailure

Field roll tests –mass unbalance(if possible)

< 0.4°/hr poor initial azimuthreference

gyro calibration shift

Field roll tests –accel. scale factor(if possible)

< 0.00015 systematicinclination error

accelerometer calibrationshift

In/Outruncomparison –inclination

Csg: mn,sd<0.3° D/P: mn,sd<0.3°

inclination error depth error or runninggear.

In/Outruncomparison –azimuth

Csg: m, sd<0.5° D/P: m,sd<0.75°

azimuth error depth error or poor gyroperformance

Final zero depth < 2.0/1000 systematic error,primarily inclination

wireline slippage orstretch – correct to CCL

Wireline stretch atTD

< 1.5/1000 systematic error,primarily inclination

tool lag on inrun –correct to CCL

Table 5.3

Quality measurescommon to allGyrodata surveys





Single station test –Earth rate

< f1(Inc,Azi)°/hr* poor initial azimuthreference

noisy data – reinitialisedeeper

Single station test –gyro drift & noise

mean<400 bits s.d.<400 bits

poor initial azimuthreference


Single station test –accel. drift & noise

mean<50 bits s.d.<50 bits

azimuth error poor gyro performance ortool movement

If1(Inc,Azi) = 1/cosInc√[(0.1°sinInc.sinAzi)²+(0.08°)²]



Initialisation - inclination

s.d. Inc < 0.1° Tool movement orcalibration shiftduring toolmake-up

knock during toolmake-up

Initialisation - azimuth

s.d. Azi < 0.2° tool movement orcalibration shiftduring toolmake-up


Initialisation - Earth rate

< f2(Inc,Azi)°/hr* Tool movement orcalibration shiftduring toolmake-up


Drift tune – X gyro <0.2°, allparams

invalid survey poor gyro performance

Drift tune – Y gyro <0.2°, allparams

invalid survey poor gyro performance

If2(Inc,Azi) = 1/cosInc√[(0.1°sinInc.sinAzi)²+(0.08°)²/6]

Table 5.4

Quality measuresfor Gyrodata

gyrocompassingsurveys

Table 5.5

Quality measuresfor Gyrodata

continuous surveys



*

" Keeper Finder 1 ) $

5447'5"

"J 7

• G <

• $

• 1 % $ $ + .

• 1$ + ).

" / )

7 '+4"

"J " 3+6H.$ 3$64 +6H$>>. $ "& >= $ 653=<6;3=<-6-3=

Zener Sub

Keeper Gyro

Cablehead

Decentraliser

Casing Collar Locator

Gamma Sensor

Temperature Sensor

Decentraliser

Pressure Barrel/Heatshield

6.35 m/ 21 ft

Figure 5.2

Keeper toolconfigured fora 9-5/8 or 7 casing survey



" +K L. +K M. " K $ ! -4° "L ! -4°

4 +5"57 <0 "' ?0760+; =

% + ( . +$. 4° >° $

# - / ) " / )-4° ""/ ) 6363°

# " + .

" ( /)

% $



4 +5"57 <0 "' ?"&7 60+; =

9

" ! *$

+N>°."

# $ ) # >,

<057=50+5"'

" 7



Field calibration –mass unbalance

DI < 0.6°/hr

DS < 1.0°/hr

poor initial azimuthreference

gyro calibration shift

Field calibration –accel. scale factor

< 0.0033 v/g systematicinclination error

accelerometer calibrationshift

Initialisation – gyrobias uncertainty



Initialisation – Earthrate horizontal



Low angle Mode –average G bias

< 0.8°/hr azimuth error poor gyro performance ortool movement

High angle Mode –average G bias

< 0.15°/hr azimuth error poor gyro performance ortool movement

Final zero depth < 1/1000 systematic error,primarily inclination

wireline slippage or stretch– correct to CCL

Wireline stretch atTD

< 1.5/1000 systematic error,primarily inclination

tool lag on inrun – correctto CCL

In/Outruncomparison –inclination

Csg: sd<0.2°

D/P: sd<0.4°

inclination error depth error or runninggear.

In/Outruncomparison –azimuth

Csg: sd<0.5° D/P:sd<0.75°

azimuth error depth error or poor gyroperformance

Table 5.6

Quality measures forKeeper multishotsurveys



($6" <

C A1 C$O A

5447'5"

!C A1 +H6= . " $ $ "

" 644°G # ( +. 634°G ( 6-44FGH + 5= .

( " / $) 54° ;4° # !

# GGO $ /C A1P) " C A1 C A1 "



7 '+4"

" C A1 & 3-3= 6;4+,44. D 3;53= --3+344. 1 >:3 +;54.

" D + D. " D " $ ! * 2 "8 $ D 9 *1 C A1 $ ) $

4 +5"57 <0 "'

C A12 " " H 6- + .

PressureBarrel

Electronics

Gyro/

Accelerometers

BreechLock

CableHead

RollerCentraliser

RollerCentraliser

Figure 5.3

The RIGS surveyprobe



( H,44< +-6444<. " " BG "

<057=50+5"'

* G )

" 7

QA measure Tolerance Failure indicates Possible cause(s) offailure

Alignmentsummary

< 0.1° Noisy Alignment Excessive ‘electrical’noise

Tool movement.

Drift checks < 0.08 ft/min Tool movement, orinvalid survey.

Poor Alignment (1st check)

Lost heading.

Sensor failure.

Tool movement.

In/Outruncomparison

within tool-definedellipses ofuncertainty

Out of specperformance at somestage in completeinrun/outrun survey. QCflow chart will indicatewhether sufficient QCparameters exist toqualify survey as withinspecification.

Depth error.

Sensor failure.

Lost heading.

'#(%

G $ $ / ) % "

Table 5.7

Quality measures forRIGS surveys



5--

G $ 7

• $

• " (

• "

G $ $1 + ,-. $ 2

Camera-based magnetic multishots are not a recommendedtool type.

# ( $ $

-

" 7

• # #

It is strongly recommended that only units ranges between0-10° and 0-24° be used.



1 O

• # ! "

• # " $ $

-

0# " $ 1 %+,:. "

<5

1 OB#

) *+%#&

1 $ 1CA D $ $ "



( " !

5--

$ $" $ 0# ( " $ ($

SRGs must not be used:

• For multishot surveys

• Deeper than 450m/1500ft below rotary table

• In hole inclinations greater than 10°

"

-%-

1 $ 1 +/1CA). 0 *"2B +/1 ). 1$1+/1C&).

Due to its historically poor performance, use of theSperry-Sun SRO tool is not recommended.

" $ # # D0& 0## $ $



" "

0+85' + 8 + "'"&5"+8'++ '"

1 #

Surface references must be established and checked by aqualified land surveyor, and recorded with a detailed stationdescription. The survey engineer on the rig must have a copyof this station description.

Drift corrections must be computed and appliedautomatically by software. Reliance on hand computationsby the survey engineer is not acceptable.

, -

/) 1 !

5--

" # " $ %



-%-

" 0 "

"

<5

" 9 7

Make sure a hard copy of the data is provided, withsufficient header data to ensure its traceability.

Insist on all data being labelled with the azimuth reference(magnetic, grid or true) and the correction, if any, applied.

Visually inspect the survey for spurious data points, oftenindicated by large dog-leg severities.

. /%%0%

'# 2 '# 1



/

# $ 6::4) 1 ( "

-#

# $ +. 1 E&C'

($6" <

#$ $ / ) $ 1 * E&C'

Engineers should seek advice from UTG beforeprogramming the Seeker tool in their wells.

*

"Finder1

Keeper"

Keeper’s L$ ( + . 63F

" " Finder $

Keeper E&C'



8

" 8 9 2 + *"2B. 6::464$><,=&(6>$><;=

-#

# D

'#(%&

# # $ +'A1'A11. ' "# ' 1

Engineers should seek advice from UTG beforeprogramming Camera-based gyro tools in their wells.

1 -

#$ /$ )



4--

5447'5"

" 0#" 7

• %

• 2 $

• A <

•

4 +5"

" 0# " / ) 2 (

# ( / ) %

<057=50+5"'

A

Where possible, the MWD engineer should keep his/her ownindependent depth tally, and seek to resolve any discrepancywith the driller’s tally.



-

5447'5"

1 7

• A +(FINDS.

•

A Battery/Memory 1GKeeper $ D 0#

<04 " '+4"

2 7 3<6H= +;.5<6H= +66. 63<>-= +6-. 9 ; 64444 3444

"

" %

"$ "



1 "

# # -3644" "

4 +5"

& ! &

#" / ) " " 63<6444 ( " $!

<057=50+5"'

" $! 1 E&C' 46Q 4-Q



# +%%&." D GGO /) GGO $ GGO

# ' " +. $

2 3+4

E&C' E& C' '# " E&C' % E&C' " '# D"A

'

2 E&C' ( " 7

• 2

•



•

• &

()

*

D E&C' $(

%+-/

E&C' C ' & 0 D"A

E&C' $

D E&C' " + .

BP

Am

ocoD

irectional Survey H

andbookB

PA

-D-004

Septem

ber 1999 Issue 1S

urvey Tools 5-37/38

ServiceCompany

JORPs document Tool Coverage Remarks

MWD Inertialgyro

North-seeking

gyro

Surfaceread-out

gyro

Camera-basedgyro

EMS Camera-based

magnetic

Tele-drift

Anadrill Anadrill MWD SurveyingProcedures Manual*

Anadrill internal proceduresdocument. Adopted asreplacement to obsolete MWDJORPs by BP Amoco.

Baker HughesINTEQ

JORPs for DirectionalMWD

BPX and BHI JORPs

Halliburton /Sperry-Sun

JORPs for SSDSDirectional MWD*

A separate documentdescribes Sperry-Sun’sInterpolation in-fieldreferencing service

Surface ReadoutGyroscope Operationsfor BPX

Covers the G2 and SRO gyros

Gyrodata BP JORPs Manual*

Scientific Drilling BP JORPs* Additional and complementaryto SORPs, SDC’s internalstandard.

Under revision at time of writing

Table 5.8 JORPs documents currently in use


September 1999 Issue 1 Technical Integrity 6-i/ii

Section 6

Contents

Page

) @ 6-1

) +$5 6-2

) *4 6-6

) ! 6-8

) A 6-20

) ) 6-22

) , 4*+B 6-29

Figure

6.1 Generic failure mode and effects anal ysis formissed target and well collision 6-4

Table

6.1 Generic classification of potential failures in thedirectional and surve y process 6-5


September 1999 Issue 1 Technical Integrity 6-1

) How to minimise the risk of a grosswell positioning error and establish anauditable trail from target definition todefinitive survey.

% & ' (

G 1 " G 1 <

'

) @

0 7

• #

•

"


6-2 Technical Integrity September 1999 Issue 1

# 7

• + .

• + (/ ).

) +$5

" ( 9 $ 7

6 (

-

> % (

"/$) 7

• " / $) ( " /)

•

• " /) /$)



8%% **58 5

& 9 2# " # / ) $ + . 9 H6 ( 92# / ) /)

* ( " $



gross surface location orsurvey error in drilled well

wrong well plan usedfor clearance scan

wrong input datafor clearance scan

wrong input to a/ctolerance calcs

clearance scanresults wrong

a/c tolerancecalculation error

a/c toleranceprint or plot error

a/c tolerance wrongor invalid on plan

inadequate surveyrunning or quality

procedures

tie-in or northreference error

survey running orquality procedures

mis-applied

unpredictablesurvey tool error

rig not at plannedlocation or elevation

change in targetapproach direction

survey programnot followed

target toleranceinvalidated while drilling

anti-collision toleranceinvalidated while drilling

wrong surface location orelevation used for planning

geological targetlocation or

boundary wronglydefined

clearance scansoftware error

inappropriate errormodel in drilled well

inappropriate error model in planned well

badly designed error model

inappropriate separation rule

badly designed separation rule

wrong input to targettolerance calculations

target tolerancecalculation error

target toleranceprint or plot error

target tolerance wrongor invalid on plan

target tolerance ignoredor misunderstood

a/c tolerance ignoredor misunderstood

drilling well plotting error

statistically extreme survey error

insufficient or inaccurate projection ahead of bit

gross survey error in drilling well

target toleraceviolated

a/c toleraceviolated

root-cause failure

knock-on effect

“on-design” event

Figure 6.1 Generic failure mode and effects analysis for missed target and well collision



'*48

" $ H6 "

A. DIRECTIONAL SOFTWARE / STANDARDS

1. Clearance scan software error

2. Badly designed error model

3. Badly designed separation rule

4. Target tolerance calculation error

5. Anti-Collision tolerance calculation error

B. DIRECTIONAL DATABASE

6. Missing data, surface location or survey error in drilled well

7. Inappropriate error model in drilled well

C. PLANNING DATA

8. Wrong surface location or elevation used for planning

9. Geological target location or boundary wrongly defined

D. DIRECTIONAL PLANNING

10. Wrong well plan used for clearance scan

11. Inappropriate error model in planned well

12. Inappropriate separation rule

13. Target tolerance printing/plotting error

14. Anti-Collision tolerance printing/plotting error

E. RIG POSITIONING

15. Rig not at planned location or elevation

F. SURVEY OPERATIONS

16. Survey program not followed

17. Inadequate survey running or quality procedures

18. Survey running or quality procedures mis-applied

19. Unpredictable survey tool error

G. DIRECTIONAL DRILLING OPERATIONS

20. Change in target approach direction

21. Target tolerance ignored or misunderstood

22. Anti-Collision tolerance ignored or misunderstood

23. Drilling well plotting error

24. Insufficient or inaccurate projection ahead of bit

25. Tie-in or north reference error

Table 6.1

Generic classificationof potential failures inthe directional andsurvey process



) *4

" 0 ) " $ " 0 ( "

7%

" %O $ ) "7

• " +. A<A $ K$ $ $ "

• " $ G 1

• 1 < 1 2 2 (

• 1 < $ G 1

2 %" O

"%O 1 D"A 1B 1"

Section 3.1describes some of thetheory and techniquesof surface positioning

Appendix Cincludes an example

of a Well LocationMemorandum



84

< $ G 1 9 % ' $ " D% $

" $ $ 1 + , & + " 9 %' 1

8%'#%

* $$ 1R

D( $ % " $ # 9

Appendix Bincludes completedexamples of a FinalWell Position Memoand a final WellLocation Data Form



) !

" $ " 7

• '

• 1

• C)

• %

• %$

& 0# $

8

" 9 $ $ "

" 9 ( $! )



'*8

" 9 ) " 7

• G O 1 ( #(G" $%' 1$#+.

& 7&'57(3 ';

• % ' D D $ ) %' + $ .

• D " D $ (

• '

+ 8 + "' 55

• %O +.

• % ' 1 1 ( #(G " D

&" 575""+0'"

• ' 9 ( D$ )



• #,+;3=(66=. "

• 1 ' 1 1 ( #(G

• #$G 1 1 ( #(G

5"#'77"5"57=

• '( 1

•

• #" GC% + ,, G.

6 + &"5"57=

• # )

• ' 0

• G " % (

4 "5"

• C' 1 ( #(G

Section 4.2 hasdetails of the relief well

drilling contingencyrequirement

Section 4.2 hasdetails of this

calculation



'$

" $ $ 7

• #

•

•

6 &"#88506+=

"

1$ # # + D . ( " 1$ # ' #) 0 " 1$ # ' <

1$# 9

6 ; "80"5 "578+ '"57 &"

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9 1$# <7

6 " "



" 7

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5 " (

%'$

# $ % ' + . + (." 1$# < #

4+4 +53 '+=656 '++ '

0+85' D5+& "+=5"7'5"

• G 7

∗ " + %O 9 % ' $ .

Section 6.6discusses the

relationship betweendirectional databases.



∗ "

∗ " +J2 C"2 .

• G 9 (7

∗ G % '

∗ C

∗ G

• +. % ' $ "8 ! +J2C"2.

• G + . +.

0+; =4+&+5088' "" + '

5+& 5" 6 +& 7&'57

+ <0+ "

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• C + . 7

∗ "

∗ " + .

∗ # + ::Q:3Q:4Q D .

• % ' 9 2( 7

∗

∗ O "8

∗ O "8

∗ $

+C8+77"&5"0"0'' 807+ 7 8 77

"

• G

• G

D

Relief wellcontingency

requirements arein Section 4.2



5"=&+ +++" 5'60+; ="+0 "

77( '

• G " 7

∗ &

∗ G

∗ D + $% .

5"5 <05 8"; 0+; =77(

(5"

• G

56 + "' 5"#'77""+0'"77

4+ ; ";75"8"0 77 45+5"

+07

• G ( 7

∗ %

∗ #

∗ %

• G + .



• G 7

∗ %

∗ %

• C $ "GC + .D 7

∗ "

∗ 9

• 9 7

∗ C

∗ G $ + .

• 9 $ 7

∗ #

∗ G

∗ G $ $

77 "+0'"5"+5"&5+ '7 5+D

5''0+5 5"088' "

• G " $



• G ) 7

∗ " $

∗ "

∗ " + .

∗ "

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• G ) +.

• G + . +.

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'%#**

' 9 R % %'

% %' 1$# $( 9( $ $

% 1$ # 9 % 7

• " ' # 1$ #R

• "

• " 9



(05--

D 1$#D ( # + . 7

• " $ " %' 1

• "

• " < + .

4 "5"8++ ' " 4+5''

8 %& ' ( D " 0 0 D$ % 7

• " "

∗ C %

∗ '<1 " 9( 7

Appendix Ccontains an exampledispensation form



∗ 1 ' < 1 " *

∗ C" (

∗ E #

∗ # G

• 2

• 1 D%

) A

G $$ " ( "



77 506+=75"

"

Certain rules (such as not crossing anti-collision tolerancelines and following JORPs) are inflexible.

1 + .

77 0+; =;575"

" "B# $ $ 1$ 7

When in doubt, re-survey.

65"7"&""#'"8+5"'

#$ ) *$ 7

• 9

• 9

• 1 $$

• 8 ( ($



7

6 *$

-

> # )

, C 7

. # )

. 1 $

) )

8

" ( 1 (

" %19 " 7

• " + .

• #

Appendix Ccontains a

Non-ConformanceReport form suitable

for this



• B B#

• "

+-

" % "

# " % % $ #%

" 7

• "

• # +.

• 9 0#

•

• # %1B#1

Survey datacomparisons arediscussed inSection 4.10



•

;%

# " ( " / )

9 ( " $ # )

"

unvalidated survey data should never be loaded on thedefinitive directional database

) " 9

" +,64. 9 B#



77 0+; =<56

" < " E&C' " '# %19

*

" ) " 1 ' 7

6 "

- "(%C' + $. )

> 1

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3 #

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40(76"&6 55

# $ $ %

/

" & ' $$ + --. " '#

55'+'57=

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• 1 $ $

•

*( 7

•

• "

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• 1

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9 7

•

• 8

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8"; 55(5

& ( % "

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5'' + +'"

D 7

•

•



% "

65+#'4=55(5'C#04

1) "

+ '"5755(5 '45+"

' $ '# " ( )

' # " ( # 2#' ' " 7

• %

• % + . -

• % + "8. 3



1 $

0 +;&75"'

% # ( $ " ( + ( .

) , 4*+B

% * $$ "

4 +8+5"' 50+

$ 1 / ) + D . # G

% < 1( 7

• '

∗ *



∗ "$

∗ *$

• &

∗ 164444

∗ *

∗ *0#

•

∗ %

∗ "

∗ (

'6"'57"; &5"

& $$ #

2 # % 1 9 #

C"7 & (5

'# " 7

• JORPs

# E&C'

Calculation oftortuosity is explained

in Section A.6


September 1999 Issue 1 Technical Integrity 6-31/32

• Approved survey error models

" (

• This Handbook

" $$ 1 1 D"A % " 1 E&C'


September 1999 Issue 1 Mathematical Reference A-i

Appendix A

+*

Contents

Page

5 '' A-1

5 4'% - A-3

5 ' A-8

5 ! 5' A-9

5 5#'' A-17

5 ) A-22

Figure

A.1 Reverse surve y calculation A-2

A.2 Geometrical construction of the pedal curve A-7

A.3 The pedal curve and uncertainties in thenorth and east directions A-7

A.4 Naming convention for sensor axes A-8

A.5 A ‘bit’s-e ye-view’ of the target: the basis of theBP Amoco target anal ysis method A-10

A.6 Graphical method of target anal ysis A-16

A.7 Calculating a no-go area on the travelling c ylinder diagram A-18


A-ii Mathematical Reference September 1999 Issue 1

Appendix A

+*

Contents (cont’d)

A.8 Derivation of the risk-based separation rule A-20

A.9 Behaviour of the risk-based separation rule atlow positional uncertainty A-21

A.10 Behaviour of the risk-based separation rule atintermediate positional uncertainty A-21

A.11 Behaviour of the risk-based separation rule athigh positional uncertainty A-22


September 1999 Issue 1 Mathematical Reference A-1

5--%A

5+*Some of the equations and formulaeunderlying the methods described inthe main part of the Handbook.

( (

5 '

'

" 7

[ ]∆∆

NMD

I A I A RF= +2 1 1 2 2sin cos sin cos .

[ ]∆ ∆E

MDI A I A RF= +

2 1 1 2 2sin sin sin sin .

[ ]∆ ∆V

MDI I RF= +

2 1 2cos cos .

C 9 RFDL

DL=

2

2tan

$

DL@+I I . I I S6+A A.T

"


A-2 Mathematical Reference September 1999 Issue 1

"

RF@6DL ( X

( DL

( Y7

RFDL DL DL

= + + +112 120

17

20160

2 4 6

( XN446° YN6>° 6 64

5 68++ ; + 0+; ='57'075"

1 ! "

P0

P2

P1 u1

u2

u0

r01

r02

r12u12

u01

α12

C

u02

" ' ' ' + ."

' ( 7

u u u112

0201

01

0212= +

r

r

r

r

A similar method,also based on

interpolating the holedirection, can be

found in

World Oil, April 1986

Figure A.1

Reverse surveycalculation



' 7

( ) ( )u u u u u u u0 1 01 0 1 01 0 2 1 01 12 0221

22 2+ = ∠

= ∠ =cos cos .P CP P P P

( )u u u u u0 01 12 02 12= −.

O' ( )u u u u u2 12 01 02 12= −.

" + . 9 >

∆D r12 1212 12

2 2=

α αcsc α12

11 2= ×−sin u u

5 4'%

-

' $ >(> (7

> (@Cnev@σ σ σσ σ σσ σ σ

n ne nv

ne e ev

nv ev v

2

2

2

A (



*(#+*%5A

" $ ( + . " $ (+ $T$ $ (7

C T C Thla

h hl ha

hl l la

ha la a

hla nev hlaT=

=σ σ σσ σ σσ σ σ

2

2

2

Thla

I A I A I

A A

I A I A I

=−

−

cos cos cos sin sin

sin cos

sin cos sin sin cos

0

#IA !

6E40

" ! 7 + . ! $ +. + . +.

0"' +5"=854""6 77

" > ! " - (7

Cne@σ σσ σ

n ne

ne e

2

2



0"' +5"=55&; "; +'57 46

" $ $ > ( (7

C T C Tnen ne

ne ene nev ne

T** *

* ** *=

=σ σσ σ

2

2

TneI A

I A* tan cos

tan sin=

−−

1

0

0

1

'57'075"86+F"57 +++ 774

" ! 7

1$ (@σmax@( )σ σ σ σ σn e n e ne

2 2 2 2 2 24

2

+ + − +

1$ (@σmin @( )σ σ σ σ σn e n e ne

2 2 2 2 2 24

2

+ − − +

" ! (ψ ψ 7

tan222 2ψσ

σ σ=

−ne

n e$:4° P:4°

" 7

σ σn e2 2> $,3°Nψ majNP,3°

σ σn e2 2< $,3°Nψ min NP,3°

"

( Cne* (



'*%7* -% -%

" >, +- . " ( > /G0 1") /G0 *8) 2( % G$1 7

χ νp,2 p

ν χ νp,2 $

+ν @-.+ν @>.

p.

Example. Find the number of standard deviations at which a 3D error ellipsoidmust be drawn to represent a 95% confidence region, assuming the well positionerrors follow a trivariate normal distribution.

Setting p = 0.95 and ν = 3, we find from tables that χ0 952. ,3 = 7.81. The 95%

confidence region is therefore represented by a 2.79-sigma error ellipsoid.

4%'98-:

" ! !#7

[ ]σσ σσ σ

σ σ σAn ne

ne en ne eA A

A

AA A A=

= + +cos sin

cos

sincos sin sin

2

22 2 22

" # ( /) $ 9#-



pedal curve

standarderror

ellipse

9 #> + .

standarderrorellipse

North

East

pedal curveor

“footprint”

σnorth

σeast

Figure A.2

Geometricalconstruction of thepedal curve

Figure A.3

The pedal curve anduncertainties in thenorth and eastdirections



5 '

* % + 1. " 7

Y-axis

X-axis

Z-axis(down hole)

GravityHighside

τ

τ = instrument toolface angle

" Gx, Gy, Gz

Bx, By, Bz + . ! 7

Inclination = I =cos−

+ +

12 2 2

G

G G G

z

x y z

sin−+

+ +

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2 2 2

G G

G G G

x y

x y z

Magnetic Azimuth = Am = ( )( ) ( )tan−

− + +

+ − +

12 2 2

2 2

G B G B G G G

B G G G G B G B

x y y x x y z

z x y z x x y y

Instrument toolface = τ = tan−

1 G

Gx

y

Figure A.4

Naming conventionfor sensor axes



" 7

G G Ix = − sin sinτ

G G Iy = − sin cosτ

Gz@GI

B B I A B I B Ax m m= − +cos cos cos sin sin sin sin cos sin cosΘ Θ Θτ τ τ

B B I A B I B Ay m m= − −cos cos cos cos sin sin cos cos sin sinΘ Θ Θτ τ τ

B B I A B Iz m= +cos sin cos sin cosΘ Θ

G, B Θ

" 7

Gravity Field Intensity@ G G Gx y z2 2 2+ +

Magnetic Field Intensity@ B B Bx y z2 2 2+ +

Magnetic Dip Angle@sin.

− + +

1

G B G B G B

G Bx x y y z z

5 ! 5'

" ) "'# " !



(45%

A ( + . "

Vi

Ui

Xi

Yiσh

σl l ij

hijφij

φi+1

φi+1− φi

NsPX

PY

b

Exclusion probability is integratedover the part of each sector

lying outside the target...

…then summedover all sectors

geological targetreference point

geological targetboundary

standard errorellipse

φi

as-surveyed pointof penetration

1 +! .δ ! + !$.α K$ ( ! ! α − °90 M$ ($

Figure A.5

A ‘bit’s-eye-view’ ofthe target: the basis of

the BP Amoco targetanalysis method



1 Nv

$ Xi Yi xii

i

X

Y=

1 $

p =

P

PX

Y

$ ( +

. $b

9(:# = ; :86 5+& (0"5+=

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−

sin

cos

cos cos

sin cos

sin

αα

δ αα δ

δ0

# ( (

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9 (

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A

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cos cos

sin

cos sin

cos

sin

0

( ( $ 7

( )[ ]U

V

highside

laterali

itc tp i

=

= − +T T x p b



4886 +0 (4"

"( +. $ ( " ( $ 7

C T C Ttch hl

hl ltc nev tc

T=

=

σ σσ σ

2

2

( )( )

pdftc

Ttc

tC

t C t= −

−1

2

1

21

π detexp

( )=−

− + −−

1

2

2

22 2 2

2 2 2 2

2 2 2π σ σ σσ σ σ

σ σ σh l hl

l hl h

h l hl

h hl lexp

t =

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h

l

r

r

→

cos

sin

φφ

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pdf r r fh l

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h l hl2 2 2 2

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π σ σ σφexp

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Ns

( 7

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2 2 221

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exp



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2σH - bH

2σL - bL2σH + bH

2σL + bL

geological targetdriller’s targetstep 3

step 5

step 4

step 6

cos Inc

cos Inc

Figure A.6

Graphical method oftarget analysis



5 5#''

-'

0+85' 4"0"' +5"=

" 7

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σsurf @ C

6

σhole @

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sin cos

I A A A A

I A A A A

I A

β ββ β

β

− − −− + −

− −

7

I @ "G

A@ #! "G

β u

interfering well

no-goarea

0

minimumallowableseparation

Figure A.7

Calculating a no-goarea on the travelling

cylinder diagram



. 7

σ1@ u C uT1

σ2 @ u C uTsurf22+ σ

7

C1 @ ' (

C2 @ (

σ surf @ C

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+ #;. % ( + $ .1

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+

=

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2

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/

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z = 0

z =

d1d2

d1 d2+

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2z =_

z = S

σ

f(z)

interferingwell

plannedwell

" ( # (

Figure A.8

Derivation ofthe risk-based

separation rule



% + 6.

Collision Risk (low position uncertainty)

Collision Risk (higher position uncertainty)

σaσb SaSb

Tolerable Collision Risk

Actual Collision Risk

Minimum Separationincreases as Combined

Position Uncertainty increases

Case 1

d + d1 2

Pσ < 0.242

# + -. "

ab

σaσb

SS


Minimum Separationdecreases as Combined

Position Uncertainty increases

Case 2

d + d1 2

P > σ > 0.242

d + d1 2

P0.399

2 ( + >.

Figure A.9

Behaviour of therisk-based separationrule at low positionaluncertainty

Figure A.10

Behaviour of therisk-based separationrule at intermediatepositional uncertainty



σaσb Sa


Tolerable Collision Risk isnever exceeded - no

Minimum Separation exists

Case 3

d + d1 2

P σ > 0.399

5 )

"D"A

the average excess dogleg severity over plan

# " DTD +

D0."

!7

[ ]D I A i MPi

Pi

Pi 0 ≤ ≤

$

[ ]D I A j NSj

Sj

Sj 0 ≤ ≤

Figure A.11

Behaviour of therisk-based separationrule at high positional

uncertainty


September 1999 Issue 1 Mathematical Reference A-23/24

9 +#6. 7

( ) ( )[ ] DL I I I I A APi

Pi

Pi

Pi

Pi

Pi

Pi= − − − −− − − −cos cos sin sin cos1 1 1 11

7

DLSD D

DLPTD

Pi

i

M

=− =

∑1

0 1

O $7

DLSD D

DLSTD

Sj

j

N

=− =

∑1

0 1

( ) ( )[ ] DL I I I I A ASj

Sj

Sj

Sj

Sj

Sj

Sj= − − − −− − − −cos cos sin sin cos1 1 1 11

" 7

Wellbore Tortuosity = DLS DLSS P−


September 1999 Issue 1 Approved Tool Error Models B-i/ii

Appendix B

Contents

Page

!

"#$% &

$' (

&

' )

*

' +

(

,


September 1999 Issue 1 Approved Tool Error Models B-1

An inventory of the survey tool error modelsapproved for use in BP Amoco.

! ""#$%

&

• ' (

• ( )#

• ( ) * #+

The standardformat for surveytool error modelsis described in

BP

Am

ocoB

PA

-D-004

Directional S

urvey Handbook

B-2 A

pproved Tool E

rror Models

Septem

ber 1999 Issue 1

MWD - Standard MWD MWD MWD with no (or no known) specialcorrections

The model allows for the fact that axialinterference may marginally exceed the upperlimit specified in Section 4.9 when the well isnear to horizontal east/west

MWD + Sag correction MWD+SAG MWD+SG MWD with a BHA deformationcorrection applied

Covers all BHA corrections, from simple 2D tofinite-element 3D models

MWD + Short Collar correction MWD+SCC MWD+SC MWD with single station axialinterference correction applied( 4.9)

“Short Collar” is the name of Sperry-Sun’scorrection, but the error model covers all such

MWD + Sag + SC corrections MWD+SAG+SC MWD+SS MWD with both BHA sag correctionand single station axial interferencecorrection applied

MWD + IHR correction MWD+IHR MWDIHR In-hole referenced MWD ( 4.8). Assumes a BHA sag correction is applied toenhance inclination accuracy

MWD + IFR correction MWD+IFR MWDIFR In-field referenced MWD ( 4.7),with time-varying field applied. Modelis applicable whether or not ShortCollar type correction is applied.

Assumes a BHA sag correction is applied toenhance inclination accuracy.

Table B.1 Approved Survey Tool Error Models – MWD (Part 1 of 2)

BP

Am

ocoD

irectional Survey H

andbookB

PA

-D-004

Septem

ber 1999 Issue 1A

pproved Tool E

rror Models B

-3

MWD + IFR [Alaska] MWD+IFR:AK MWDIAK In-field referenced MWD in Alaska Model takes account of increased violenceof magnetic field disturbances in Alaska.Assumes a BHA sag correction is appliedto enhance inclination accuracy

MWD + IFR [ Wytch Farm] MWD+IFR:WF MWDIWF In-field referenced MWD at WytchFarm

Model takes account of observed lowlevels of axial low level interference usingAnadrill BHA components and design.Assumes a sag correction is applied toenhance inclination accuracy

MWD + IFR + Multi-station MWD+IFR+MS MWDIMS In-field referenced MWD with multi-station analysis and correction( 4.9) applied in post-processing

Assumes a BHA sag correction is appliedto enhance inclination accuracy

MWD + Crustal Anomaly corrn MWD+crust MWD+CA MWD where local magnetic field hasbeen measured (or derived fromaero-magnetic data) and correctedfor, but short-term time variations arenot applied.


MWD + Crustal + SC corrections MWD+CA+SC MWD+CS Same as MWD + Crustal Anomalycorrection but with single station axialinterference correction applied


Table B.1 Approved Survey Tool Error Models – MWD (Part 2 of 2)

BP

Am

ocoB

PA

-D-004

Directional S

urvey Handbook

B-4 A

pproved Tool E

rror Models

Septem

ber 1999 Issue 1

EMS - Standard EMS EMS Electronic multishot with no (or noknown) special corrections

Includes ex-BP “Electronic Single Shots”model. Assumes large axial interferenceerrors have been corrected.

EMS + Sag correction EMS+SAG EMS+SG Electronic multishot with a BHAdeformation correction applied

Covers all BHA corrections, from simple 2D tofinite-element 3D models. Assumes large axialinterference errors have been corrected.

EMS + IHR correction EMS+IHR EMSIHR In-hole referenced electronicmultishot ( 4.8).


EMS + IFR correction EMS+IFR EMSIFR In-field referenced electronicmultishot ( 4.7), with time-varyingfield applied. Model is applicablewhether or not Short Collar typecorrection is applied.


EMS + IFR [Alaska] EMS+IFR:AK EMSIAK In-field referenced electronic inAlaska

Model takes account of increased violence ofmagnetic field disturbances in Alaska.Assumes a BHA sag correction is applied toenhance inclination accuracy

EMS + Crustal Anomaly corrn EMS+crust EMS+CA Electronic multishot where localmagnetic field has been measured(or derived from aero-magnetic data)and corrected for, but short-term timevariations are not applied.

Assumes large axial interference errors havebeen corrected.

Table B.2 Approved Survey Tool Error Models - Electronic Magnetic Multishots

BP

Am

ocoD

irectional Survey H

andbookB

PA

-D-004

Septem

ber 1999 Issue 1A

pproved Tool E

rror Models B

-5

BHI RIGS multishot RIGS RIGS INTEQ RIGS multishot surveys

BHI Seeker multishot Seeker MS SKR MS All INTEQ Seeker ( 5.8) multishotsurveys

Ferranti FINDS multishot FINDS FINDS All Ferranti FINDS ( 5.8) surveys

Gyrodata - gyrocompassing m/s GYD GC MS GYD GC Older Gyrodata gyro multishots, plusall battery/memory tool surveys(RGS-BT)

Replaces ex-BP “Gyrodata multishot intoopen hole” model.

Gyrodata - cont. casing m/s GYD CT CMS GYD CC Gyrodata multishot surveys withcontinuous tool (RGS-CT) in casing.OD 13-3/8” or less.

Gyrodata - cont. drillpipe m/s GYD CT DMS GYD CD Gyrodata pump-down multishotsurveys with continuous tool (RGS-CT) in drill-pipe.

Gyrodata - large ID casing m/s GYD LID MS GYD LC Gyrodata multishot surveys(gyrocompassing or continuous tool)in larger size casing strings (greaterthan 13-3/8” OD).

Includes an increased misalignment term

Gyrodata – bat/ mem drop m/s GYD BM MS GYD BM Gyrodata multishot usingBattery/Memory tool in anyconfiguration.

Table B.3 Approved Survey Tool Error Models - North Seeking and Inertial Gyro Multishots (Part 1 of 2)

BP

Am

ocoB

PA

-D-004

Directional S

urvey Handbook

B-6 A

pproved Tool E

rror Models

Septem

ber 1999 Issue 1

Schlumberger GCT multishot GCT MS GCT GCT surveys in casing or open hole. GCT = “Gyro Continuous Tool” ( 5.8)

SDC Finder - multishot Finder MS FDR MS Finder multishots in casing or drillpipe

Replaces ex-BP “Inrun” and “Outrun” models

SDC Keeper - casing m/s KPR csg MS KPR CM Keeper multishot surveys in casing.OD 13-3/8” or less.

SDC Keeper - drillpipe m/s KPR d/p MS KPR DP Keeper pump-down multishot surveysin drill-pipe.

SDC Keeper - large ID csg m/s KPR LID MS KPR LC Keeper multishot surveys in largersize casing strings (greater than13-3/8” OD).

Includes an increased misalignment term

Sperry-Sun G2 multishot G2 gyro MS G2 MS G2 ( 5.8) multishots in casing, drillpipe or open hole

Replaces ex-BP “Static” and “Dynamic”models

Table B.3 Approved Survey Tool Error Models - North Seeking and Inertial Gyro Multishots (Part 2 of 2)

BP

Am

ocoD

irectional Survey H

andbookB

PA

-D-004

Septem

ber 1999 Issue 1A

pproved Tool E

rror Models B

-7

Inclinometer ( Totco/ Teledrift) INC INC Inclination only surveys in near-vertical hole, including TOTCO,Teledrift and Anderdrift.

Inclinometer + known azi trend INC+trend INC+TR Inclination only surveys in near-vertical hole, where formation dip andexperience enables direction of driftto be predicted.

Replaces ex-BP “Inclinometer (azimuth inknown quadrant)” model

Table B.4 Approved Survey Tool Error Models - Inclination Only Surveys

BP

Am

ocoB

PA

-D-004

Directional S

urvey Handbook

B-8 A

pproved Tool E

rror Models

Septem

ber 1999 Issue 1

Camera-based mag single shot CB mag SS CBM SS Traditional (mechanical) magneticsingle shot ( 5.5)

Assumes tandem probes are run and thatboth are adequately magnetically spaced.Replaces ex-BP “PMSS”.

Conventional SRG single shots SRG SRG Optically-referenced gyro single shots( 5.6) Includes SDC Keeper whenused in “siteline reference mode”.

Tool types include SRG and MSRG(scientific Drilling), Sigma (INTEQ) andSRO (Sperry-Sun).

Camera-based gyro single shots CB gyro SS CBG SS Traditional surface referenced gyrotool run on wireline, including “levelrotor” gyros and Sperry-Sun SU3.

Replaces ex-BP “PGSS” model.

Gyrodata - gyro single shots GYD SS GYD SS Gyrodata gyro orientation surveys

SDC Keeper - gyro single shots KPR SS KPR SS Keeper gyro orientation surveys Excludes siteline (ie. surface) referencedsurveys

SDC Keeper – surface ref s/s KPR SR SS KPR SR Keeper gyro orientation surveys,where azimuth alignment is achievedby optical referencing at surface.

SDC Finder - gyro single shots Finder SS FDR SS Finder gyro orientation surveys

NS Gyro single shots NS gyro SS NSG SS North seeking gyro orientationsurveys taken with unspecified tool.

Note Gyrodata, SDC Keeper and SDCFinder have their own models, whichshould be used if the tool type is known tobe one of these.

Table B.5 Approved Survey Tool Error Models - Other Single Shot Types

BP

Am

ocoD

irectional Survey H

andbookB

PA

-D-004

Septem

ber 1999 Issue 1A

pproved Tool E

rror Models B

-9

Camera-based gyro multishot CB gyro MS CBG MS Traditional optically referenced gyrosurveys run on wireline, including“level rotor” gyros and Sperry-SunSU3 ( 5.8).

Replaces ex-BP “PGMS” model.

Camera-based magnetic multishot CB mag MS CBM MS Traditional (mechanical) magneticmultishot ( 5.5)

Assumes adequate magnetic spacing.Replaces ex-BP “PMMS”.

Dipmeter or other wireline log Dipmeter DIPMTR Wireline conveyed logging tools withdirectional survey capability ( 5.7).

Schlumberger OBDT, BGT are examples

Sperry-Sun BOSS gyro multishot BOSS gyro BOSS Sperry-Sun BOSS multishot surveys( 5.8).

Table B.6 Approved Survey Tool Error Models - Other Multishot Types

BP

Am

ocoB

PA

-D-004

Directional S

urvey Handbook

B-10 A

pproved Tool E

rror Models

Septem

ber 1999 Issue 1

Blind drilling Blind n/a Hole intervals where no surveys aretaken

Model assumes well direction deviatesfrom last known survey at a constant rate.Errors grow with square of distance drilled.

Unknown survey Unknown n/a Any survey data of unknown ordubious type

Replaces ex-BP “unknown multishot”model.

Zero Error model Zero Error n/a Used to set position uncertainty tozero down to a given depth (eg. side-track point).

Table B.7 Approved Survey Tool Error Models - Special Models


September 1999 Issue 1 Data and Work Sheets C-i/ii

Appendix C

Contents

Page

C-5

C-8

C-9

C-10

C-12

C-14

C-16

! C-18

" #" ! C-20

$ % ! C-22

&% ! ' C-27


September 1999 Issue 1 Data and Work Sheets C-1

(

Checklists and proformas to facilitateauditability and quality assurance.

!! "#$%& # '(&' )* & +% , + ,

# )* ! ' ) "

#


C-2 Data and Work Sheets September 1999 Issue 1

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The function ofthe Well LocationMemorandum is

discussed in moredetail in Section 6.3

DGPS and othersurface positioning

systems aredescribed inSection 3.1



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WELL LOCATION MEMORANDUM

LOCATION DESIGNATION

This WLM supersedes the following previous locations:

(NB: Any change in shotpoint location must have a new location designation)

Country: Prospect/Field:

Region/State: Lease/PSC/Block:

1. WELL LOCATION DEFINITION (To be completed by Buisiness Unit subsurface and/or reservoir team)

SURFACE LOCATION:PRIMARY DEFINITION: 3D, 2D, HR Seismic Survey or OTHER* (* Circle appropriate definition)

Survey name: Survey mnemonic:

3D Inline bin, orDatabase type & name: 2D/HR line number:

3D Xline bin, orAcquisition contractor & year: 2D/HR shot number:

3D bin size (Inline x Xline):Processing contractor & year: or 2D/HR shotpoint interval:

OTHER DEFINITION (eg: template & slot No.):

SECONDARY DEFINITION: 3D, 2D or HR* Seismic Survey (* Circle appropriate definition)





PRIMARY DRILLING TARGET LOCATION (for non-vertical wells):

PRIMARY DEFINITION: 3D, 2D or HR* Seismic Survey (* Circle appropriate definition)





Section 1 completed by: Section 1 approved by:

Signature: Signature:

Date: Date:

Name: Name:

Position/Job Title: Position/Job Title:



Well Location Memorandum - Page 2 LOCATION DESIGNATION

2. SUBSURFACE DATA (To be completed by Business Unit Subsurface Team)Attach a separate map sheet to this WLM showing seismic lines and geological structure around target location

Describe below in words and diagramatically the surface location and it's constraints (give dimensions):

Proposed Location

TOLERANCE Define Surface Location Tolerance(s)

Surface Location Area Diagram

Illustrate shape and size of the zone within which a surface location

would be acceptable and indicate constraints which limit rig

anchoring or manoevring (eg: shallow gas, obstructions, pipelines).

For location(s) derived from workstation provide:Coordinates of surface and primary target locations and two other bins remote from the primary target

(one bin with same Inline and one with same Xline bin number as primary target)

Location 3D Survey Name Bin Size Inline Xline Eastings Northings

Surface:

Primary Target:

Same Inline:

Same Xline:

For surface and target locations based on 2D or HR seismic provide:

Location 2D/HR Survey Name Point* Line No. Shotpoint Eastings Northings

Surface:

Primary Target:

* Mapped point type (SP, CDP, etc)

Attach extract of relevant 2D and/or HR line from database listing shotpoint coordinates values for

2km either side of proposed location



Well Location Memorandum - Page 3 LOCATION DESIGNATION

3. WELL LOCATION COORDINATES (To be completed by UTG SURVEY GROUP)

LOCATION COORDINATES

SURFACE LOCATION (Vertical or Deviated well) PRIMARY TARGET L OCATION (Deviated well)

Latitude: Latitude:

Longitude: Longitude:

Eastings: Eastings:

Northings: Northings:

Surface Positioning Tolerance: True azimuth from surface location: degrees

Water depth: Horizontal offset distance: m ft

Ground Elevation:

Geodetic Information:

Datum name: Datum mnemonic:

Ellipsoid name: Ellipsoid mnemonic:

Projection name: Projection mnemonic: Zone:

Data source of coordinates (eg: database name, report, etc):

Surface Location:

Primary Target Location:

Seismic survey positioning systems and horizontal accuracy estimates:Surface Location Primary Target Location

Positioning System Accuracy Positioning System Accuracy

3D Seismic:

2D Seismic:

HR Seismic:

Other positioning information:

Section 3 completed by: Section 3 approved by:

Signature: Signature:

Date: Date:

Name: Name:

Position/Job Title: Position/Job Title:

Circulation:

D.S. / S.D.E. / D.E. Site Investigation Specialist

Subsurface Team Leader Data Administrator (load to database)

Asset Geoscientists Head of Survey



")*$*")*)-)

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BP

Am

ocoD

irectional Survey H

andbookB

PA

-D-004

Septem

ber 1999 Issue 1D

ata and Work S

heets C-9

Country: Area: Well Number:

Prospect/Field: Submit to BP Amoco Survey for checking/approval Location designation:

Date Completed:

Accepted Sur face Pos i t i on Secondary Positioning System Contractors report no.

(Geogs: 2 dec places, Grid: 1 dp (m) 0 dp (ft)) (Geogs: 3 dec places, Grid: 2 dec places) Geodetic ParametersLat: ° Long: °

Geodetic Datum Projection and zone: ! Ref.Stn.1: Name/Country: Associated Ellipsoid "!#!#$ !%

Easting: && Northing: & & Lat. Long. Semi-major axis & '

Radius of error: ( ' Primary Positioning System Easting Northing Semi-minor axis(Geogs: 3 dec places, Grid: 2 dec places) Dist to Ref.Stn. km Reciprocal flattening 1/

System/method for Names of Reference Station(s) used for Ref.Stn.2: Name/Country: Datum Shiftaccepted position )*+$, -. Primary Position Lat. Long. From WGS84 to Local Datum

Easting Northing dX: ' dY: ' dZ: ( 'Secondary positioning Dist to Ref.Stn. km rX: rY: rZ: (&

system: %#+$, -. Antenna Position: WGS84 Datum Ref.Stn.3: Name/Country: Scale Factor: //'

Lat: ° Lat. Long. Useful Information / Notes

Rig positioning contractor: 0112 Long: ° Easting NorthingJob number: Sph. Ht. Dist to Ref.Stn. km 3$4 + ' '/$%5 6* 7 83 9$%%$'4 ! 4 !

Site survey date: Antenna Coords: Network Solution $%% 4##$ ! + #3 $#$ !% :*

Contractor: Offset: Antenna to rotary WGS84 Datum 7!56 ) # %% 5$!#4 43 ;! Report number: (Relative range/bearing) Lat. ° correct.

Rig name: ! 0 3 & ' < ° Long ° Sph.Ht.Coords of rotary: Local Datum

Type of rig: Lat: ° S.D. X: Y: Z:

Vertical datum: Long: ° & Offset: Antenna to rotary (Rel. range/bearing)

! 2:% Ellip. Ht. ' < ° B.M.S.L. Easting: && Coords of rotary: Local Datum

Water or stated ' Northing: & & Lat. ° depth Vert Datum Long °

B.L.A.T. ' S.D. X: Y: Z: Easting: & S.D.RTE A.M.S.L && ' Northing & & S.D.

Diagram Diagram

Rig Hdg309.7 deg T

R/T

1.0

m

56.3 m

GPS Antenna

Rig Hdg309.7 deg T

R/T

17.4

m

42.55 m

GPS AntennaCompleted by:(block caps) 1"7

Checked by:(block caps) =>



WELL PLAN DATA SHEET * delete as appropriate

Rig / Platform / Drill Site* Well

Sheet completed by Date

SURFACE LOCATION planned / actual* Datum/Ellipsoid Projection

Structure reference DescriptionLat. N / S* EastingLong. E / W* Northing

Well reference point DescriptionLat. N / S* EastingLong. E / W* NorthingOffset from structure ref. N / S* E / W*

Elevation (land rig) Elevation (offshore)Drill datum RT / KB* Drill datum RT / KB*Drill datum to well ref. pt. Drill datum to MSLWell ref. pt. to MSL Drill datum to well ref. pt.

TARGET #1 TARGET #2 TARGET #3Name Name NameEasting Easting EastingNorthing Northing NorthingDepth TVDss Depth TVDss Depth TVDssTolerance Tolerance Tolerance

Survey reference True / Grid* North arrows (diag.)Grid convergence (T to G) E / W*Magnetic declination (T to M) E / W*Magnetic model DateCorrection (magnetic to survey ref.)Correction (true to survey ref.)

Curved conductorsDrill datum to well reference point

MD TVD North EastN / S* E / W*

Incl. at w.r.p. Azim at w.r.p.



WELL PLAN DATA SHEET * delete as appropriate

Rig / Platform / Drill Site*

Well

Sheet completed by Date

SURFACE LOCATION planned / actual* Datum/Ellipsoid Projection !"# $%% &' ()*

Structure reference Description + Lat. $°,-%$. N / S* Easting / 0 ,$1Long. $$°%-. E / W* Northing 0 ,$%1$1

Well reference point Description + $ (+! 23*Lat. $°,-%. N / S* Easting / 0 ,$$Long. $$°%-%. E / W* Northing 0 ,$%1%Offset from structure ref. %- N / S* 1%- E / W*

Elevation (land rig) Elevation (offshore)Drill datum RT / KB* Drill datum RT / KB*Drill datum to well ref. pt. Drill datum to MSL 1-Well ref. pt. to MSL Drill datum to well ref. pt. $%-

TARGET #1 TARGET #2 TARGET #3Name Name NameEasting / 0 ,$$ Easting / 0 , EastingNorthing 0 ,,1 Northing 0 ,,$ NorthingDepth TVDss %%- Depth TVDss - Depth TVDssTolerance Tolerance Tolerance- " ,% 4 ,1 - 4! ,$ 4 ,,$ - 5 ,$ 4 ,, - +6 ,% 4 ,,

Survey reference True / Grid* North arrows (diag.)Grid convergence (T to G)Magnetic declination (T to M)Magnetic model 77' Correction (magnetic to survey ref.)Correction (true to survey ref.)

,1° E / W*° E / W*

Date 8

,°,1°

Curved conductorsDrill datum to well reference point

MD TVD North East$- $%- %1- N / S* - E / W*

GM

decl. = +0.11

conv. = +2.34

Incl. at w.r.p. 1° Azim at w.r.p. %$$°



DIRECTIONAL DESIGN CHECK LIST

Rig / Platform / Drill Site Well

DateSheet completed by

Checked by

/ CommentWell ObjectivesDocument from BU sub-surface teamUpdates to well objectives

Well Location Memorandum

Planning FileWell Plan Data SheetSurvey Program Data SheetProposed well trajectoryBU sub-surface approval of trajectoryTarget analysis (1 per target)

Offset well data (surveys, completion diags. etc.)Initial clearance scan (global scan)Tolerable Collision Risk Worksheet(s)Minimum separation calculationsAnti-Collision Instruction Sheet

Magnetic interference prediction

Relief well contingency calculation

Dispensations from Recommended Practice

Wellsite DrawingsPlan view drawingsVertical section drawingsStructure (spider) plots

Travelling cylinder - global clearance scanTravelling cylinder - working drawing(s)Travelling cylinder - wellsite plots



DIRECTIONAL DESIGN CHECK LIST



,

Checked by +9:

/ CommentWell ObjectivesDocument from BU sub-surface team 5 !! !#; <=; ,

Updates to well objectives !" != <= 9!:

Well Location Memorandum 5::!9;

Planning FileWell Plan Data Sheet

Survey Program Data Sheet

Proposed well trajectory 8":= %

BU sub-surface approval of trajectory <= 9!:

Target analysis (1 per target)

Offset well data (surveys, completion diags. etc.) 9:= 3:!"!9 !!3

Initial clearance scan (global scan)

Tolerable Collision Risk Worksheet(s)

Minimum separation calculations + +> ":=6

Anti-Collision Instruction Sheet

Magnetic interference prediction + +> ":=6

Relief well contingency calculation

Recommended Practice Dispensation Form(s) !" =):3= 8

Wellsite DrawingsPlan view drawings

Vertical section drawings ?

Structure (spider) plots "@6:"3

Travelling cylinder - global clearance scan

Travelling cylinder - working drawing(s)

Travelling cylinder - wellsite plots ?

BP

Am

ocoB

PA

-D-004

Directional S

urvey Handbook

C-14 D

ata and Work S

heetsS

eptember 1999 Issue 1

SURVEY PROGRAM DATA SHEET

Rig / Platform / Drill Site Well Program version Sheet completed by Date

Survey Tool / Error Model Hole Casing Depth interval Comments / ContingencySize Size from to

BP

Am

ocoD

irectional Survey H

andbookB

PA

-D-004

Septem

ber 1999 Issue 1D

ata and Work S

heets C-15

SURVEY PROGRAM DATA SHEET

Rig / Platform / Drill Site

Well

Program version

Sheet completed by

Date

Survey Tool / Error Model Hole Casing Depth interval Comments / ContingencySize Size from to

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ANTI-COLLISION INSTRUCTION SHEET



BU authorisation

The instructions given in this sheet are based on: 999

Well plan no. Date Survey program no. Date

and are not otherwise valid.

Wells to be Shut InMinimum Shut-in Interval

Well name Slot MD from MD to Comment

Minor Risk WellsWell name TCR* Key Assumptions

*Tolerable Collision Risk

Travelling Cylinder PlotsPlot no. Depth from Depth to Date Comment

Contingency Plans / Special Instructions



ANTI-COLLISION INSTRUCTION SHEET



BU authorisationA:9 2" ,

The instructions given in this sheet are based on:Well plan version no. Date

1

Survey program version no. Date1 ,

and are not otherwise valid.

Well Shut-insMinimum Shut-in Interval

Well name Slot no. MD from MD to Comment% $- - # ?! !6 :) . !:=

, $- ,- : !B

Minor Risk WellsWell name TCR* Key Assumptions

*Tolerable Collision Risk

Travelling Cylinder PlotsPlot no. Depth from Depth to Date Comment

$- ,1- 1

,1- 1

Contingency Plans / Special Instructions

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9!6" =!"C :":=! ":" 9!# ": !9 !B!" ) 9! "2!2::C ) ::=



DISPENSATION FROM RECOMMENDED PRACTICE

To be used for recording planned violations of standard directional and survey procedures and recommended practices


DateSheet prepared by

Recommended Practice Document

Procedure / Standard to be violated

Details of Dispensation Requested

Justification

Attachments

Technical Assessment / Recommendation Signature / Date / Comment

BU Authorisation



DISPENSATION FROM RECOMMENDED PRACTICE

To be used for recording planned violations of standard directional and survey procedures and recommended practices



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Recommended Practice Document:"C 89= :":=! !: ) :=

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BU Authorisation

"83

=; :"C 5 &; $



NON-COMPLIANCE / NON-CONFORMANCE REPORT

To be used for reporting unplanned violations of standard directional and survey proceduresor unplanned deviations from directional plan or survey program



Procedure / Standard / Plan / Program document

Procedure / Standard / Plan / Program violated

What happened

Most serious likely consequence

Contributory causes

Action Responsible Date



NON-COMPLIANCE / NON-CONFORMANCE REPORT

To be used for reporting unplanned violations of standard directional and survey proceduresor unplanned deviations from directional plan or survey program



=3C +9: % %

Procedure / Standard / Plan / Program document "::= ""!9 := % +6"8C:= ""!9

Procedure / Standard / Plan / Program violated 1. := '5G< +! "":= +6"8C

What happened'5 6"8C := 1. := B" = ""3 )" < ! := "!:9 :":=!

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9!=C "!:= +6"8:" ":" 63

+9: %



List all the consequencesof collision and the

necessary remedial action

STOPUse

Conventionalrule - Major

risk

Are theconsequences

of collisionpredictable

?

Do theconsequences

of collision include a riskto personnel or the

environment?

Estimate the totalcost of collision

Estimate the valueof the planned wellto the BU

Is there apractical way to

substantially reduce eitherthe probability of collision or

the severity of theconsequences

?

noyes

no

no

yes

yes

Prepared by:

Authorised by:

How could the probability of collision or theseverity of the consequences be reduced ?How might this impact the drilling operation ?

Accepting a finite risk of collision will reduce thevalue of the planned well. What reduction, as afraction of the total value, are you prepared totolerate ? (guideline = 0.05)

Tolerable Collision Risk =

Estimate the totalcost of substantiallyreducing the risk

Given the uncertainty in the above estimates, byhow many times must the savings made from notreducing the risk outweigh the risk itself ?(guideline = 20)

M =

Tolerable CollisionRisk Worksheet

= 1 in

=

> 1 : close approach tolerances need not be set

< 1 :Tolerable

Collision Risk = 1 in

Use this sheet to justify classifying a well as Minor risk and toestablish the Tolerable Collision Risk for use in risk-based

well separation rule.Ref. BPA-D-004 (Dir. Svy. H’book) Sections 4.2, 4.3

V =

C =

F =

VF

C

VF

C

VF

C

C

VFF

M= =1

V =

H.Williamson, UTG Well Integrity

Key Assumptions (Elements of the drilling program which are critical to the above analysis)

Scenario Name:

(Be specific. Include all factors which affect eitherthe cost of collision or the cost of reducing the risk)

Description:





STOPUse


risk

Are theconsequences


?

Do theconsequences


environment?






?

noyes

no

no

yes

yes

Prepared by: Stuart Telfer (Directional Engineer)

Authorised by: Richard Harland (Ops Superintendant)






M =


= 1 in

=


< 1 :Tolerable


V =

C =

F =

VF

C

VF

C

VF

C

C

VFF

M= =1

V =

H.Williamson, SPR Well Design

Marnock A01Y Parallel S/T in Reservoir

Sidetracking an existing well (A01Z) by paralleling it through the reservoir section. Original well is sidetracked below the 13 3/8” casing drilling 12 1/4” and 8 1/2” hole sections. The original well, under conventional rules is classed as MINOR risk as it is closedin and abandoned. Interference occurs in 8 1/2” hole from4060m to 4590m.

1. Estimated treatment due to contamination from original wellbore and potential mud loss £ 50k Mud loss is not expected, merely contamination through barite sag in the original hole requiring treatment to the sidetrack hole system.2. Potential well control due to reservoir fluid on the highside of the original wellbore £ 200k (est. 2 days rig time @ £100k/day)3. Plugback and sidetrack well (est. 6 days rig time @ £100k/day) £ 600k

Moving South edges of the drillers target Northby 10m at entry and 63m at TD would result in:

1. Increased directional control to achieve smaller targets, cost in extra rig time = 8 days

2. Increased risk of sticking by 25% through greater sliding requirement, potential impact of becoming stuck, 12 days rig time.

0.25 x 12 days = 3 days

Total = 11 extra days @ £100k/day

£ 1.10 m

20 0.05

0.065

15

850k



Scenario Name:


Description:






STOPUse


risk

Are theconsequences


?

Do theconsequences


environment?






?

noyes

no

no

yes

yes

Prepared by: Larry Wolfson 12/6/96

Authorised by: Adrian Clark 15/6/96






M =


= 1 in

=


< 1 :Tolerable


V =

C =

F =

VF

C

VF

C

VF

C

C

VFF

M= =1

V =


Niakuk Segment 3/5 Development Wells

New development wells drilled to segment 3/5 locationsencountering interference with adjacent wells. Shallownudges and varying KOPs used to move the interferencedepth below the surface casing.

• Collision with a producer/injector results in a side-track of that well: $2-$2.5 million (based on P2-50B)• Plug back and side-track the drilling well: $200k - $500k• The cost of delayed production/injection from both wells is estimated at $60 per bopd. NK-10 is a significant injector that supports 12,000 bopd and the average production from the producers is 3,000 bopd. The cost of a collision includes delayed production for both wells: - Injector: $900k - Producer: $360k• Estimated total cost (range): $2.56 - $3.90 million.

0.103

10

$3.9 million

$8.0 million

0.05



Scenario Name:


Description:


Surface casing set above start of zone of interference (6,600 ft MD)





STOPUse


risk

Are theconsequences


?

Do theconsequences


environment?


Estimate value ofthe planned wellto the BU




?

noyes

no

no

yes

yes

Prepared by: James O’Connor

Authorised by: Liam Cousins (Ops Superintendant)






M == 1 in

=


< 1 :Tolerable


V =

C =

F =

VF

C

VF

C

VF

C

C

VFF

M= =1

V =


Mungo 22/20-A09(169)[W12]

Interference with previous exploration and development wellswhen achieving W12 target. Well plan must pass between thetwo wells to achieve W12 target. Both wells are suspended.The development well is awaiting abandonment. The section ofgreatest collision risk with the development well has highpercentage casing wear and is of no future use to the asset.

Collision with either well would provide a conduit for reservoir pressure to into the 12 1/4” section of the planned well. However as the reservoir pressure is c.1.3sg and drilling fluid is 1.65sg the risk of a well control incident is no greater than when Top Reservoir Target is reached in 12 1/4” section.Estimated costs:1. Plugback and sidetrack well (estimate 4 days rig time @ £140k/day) £ 560k2. Bit damage (estimate £50k) £ 50k

Programmed FIT achieved at 13 3/8” casing shoe (the drilling programme calls for revision of risks if the FITis not achieved).

Collision risk would be reduced if the wellpathaccessed the area via a much more tortuouspath.

•250mMD extra -> £150k

•increased risk of stuck pipe -> £150k

•increased risk of not setting casing -> £300k

£600k

200.05

0.049

20

610k




Scenario Name:


Description:




#


September 1999 Issue 1 Data and Work Sheets C-27/28

DIRECTIONAL SURVEY HANDBOOK (BPA-D-004) - CHANGE REQUESTForward to the Directional & Survey Specialist, UTG Well Integrity Team

Request made by: Date:

Business Unit / Organisation:

Job Title:

Tel: E-mail:

Section Title: Page(s) affected:

Details of Change

UTG / ODL Action

directional survey

Documents