amoco - directional survey handbook

5/21/2018 Amoco - Directional Survey Handbook

1

Upstream

Technology

Group

ISSUE 1

SEPTEMBER 1999
http://prelims.pdf/http://prelims.pdf/http://prelims.pdf/


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BP Amoco

Directional Survey Handbook BPA-D-004

September 1999 Issue 1 i

Contents

Authorisation for IssuePreface

Amendment Summary

Section 1 Introduction

1.1 About this Handbook

1.2 Directional Survey and Value Addition

1.3 The Design-Execute Principle

Section 2 Policy and Standards

2.1 Drilling and Well Operations Policy

2.2 Policy Expectations

2.3 Standard Practices

Section 3 Theory

3.1 Surface Positioning3.2 The Earths Magnetic Field

3.3 Position Uncertainty

3.4 Position Uncertainty Calculations

Section 4 Methods

4.1 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
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BPA-D-004 Directional Survey Handbook

ii Introduction September 1999 Issue 1

Contents (contd)

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 ModelsAppendix C Data and Work Sheets
http://section5a.pdf/http://section6a.pdf/http://appa-a.pdf/http://appb-a.pdf/http://appc-a.pdf/http://appc-a.pdf/http://appb-a.pdf/http://appa-a.pdf/http://section6a.pdf/http://section5a.pdf/


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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 also

available online via the wellsONLINE and ASK websites, accessible on

the BP Amoco Intranet. The online document is to be considered the

master version, containing the most up-to-date information.

The distribution of this document is managed by the Upstream

Technology Group (UTG) and controlled and administered in Aberdeenby ODL.

ODL may be contacted as follows:

UTG DCC or: UTG DCC

ODL ODL Mailbox

Buchanan House BP Amoco, Dyce (through internal mail)

63 Summer Street

Aberdeen AB10 1SJScotland

Tel 44 (0)1224 628007

Fax 44 (0)1224 643325

Alternatively, contact the UTG Wells Document Controller,

Steve Morrison at BP Amoco, Dyce, Extn 3593 (44 (0)1224 833593


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September 1999 Issue 1 vii/viii

Amendment Summary

Issue No Date Description

Issue 1 Sept 1999 First issue of document.


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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
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September 1999 Issue 1 Introduction 1-1

Who this Handbook is for, and what

its about.

Reference to

another sectionin the Handbook

Reference to atechnical paperor publication

Indicates a BP

Amoco StandardPractice


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1-2 Introduction September 1999 Issue 1


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The wells 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.

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.

The purposeand content of theDirectional Design

and Well Survey Filesare explained in

Sections 6.4 and 6.6


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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


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

Section 2

Contents

Page

2-2

2-3

2-9
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September 1999 Issue 1 Policy and Standards 2-1

What BP Amoco Policy says about

directional 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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Getting

HSE Right

italics

(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 how

it 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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Getting HSE Right


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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 wellsobjectives

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.

JORPs arediscussed in

Section 5.10


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Sb Sb

Sb

( )

22

1

2

1 2

1 2ln

d d

Rd d Sb

+ + + +

1

2

2

2+R


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September 1999 Issue 1 Theory 3- i

Section 3

Contents

Page

3-1

3-17

3-21

3-26

Figure

3.1 The Earths surface and the geoid 3-2

3.2 Globally and locally fitting ellipsoids 3-3

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

3.4 Relationship between 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 two directions 3-24

3.10 Principal directions and the standard error ellipse 3-25
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3-ii Theory September 1999 Issue 1

Section 3

Contents (contd)

Table Page

3.1 Definition of the drilling grid in some

BP Amoco operation areas 3-93.2 The magnetic field in some of BP Amocos operating areas

(approximate values as of 1 July 1999) 3-19

3.3 Confidence intervals for the one dimensionalnormal distribution 3-23

3.4 Confidence intervals for the two dimensionalnormal distribution 3-25

3.5 Error term propagation modes 3-27
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September 1999 Issue 1 Theory 3-1

An introduction to the science of well

surveying.


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3-2 Theory September 1999 Issue 1

Ocean

The Earth

Mountain Range

Geoid

Figure 3.1

The Earths surfaceand the geoid


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geoidglobally fitting

ellipsoid

eg. WGS 84

locally fittingellipsoid

eg. Clarke 1866

area of bestfit of ellipsoid

to geoid

black

latitude

greylatitudeEQUATOR

grey ellipsoid Point

perpendicular to grey ellipsoid

black ellipsoid perpendicular toblack ellipsoid

Figure 3.2

Globally and locallyfitting ellipsoids

Figure 3.3

Dependence oflatitude on choice ofellipsoid and datum


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geoid height

(N)

ellipsoidalheight (H)

gravity-related

height (h)

H = h + N

Ellipsoid

Geoid

Figure 3.4

Relationship betweengeodetic heights


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ED50 / UTM zone 31N Nord Sahara

1959 / UTM zone 31N


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Central Meridian

drilling grid lines of latitiude

and longitude

mapping grid

Cross-section

shown infigure 3.6

West of theCentral Meridian,grid convergence

is negative

East of theCentral Meridian,grid convergence

is positive

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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Central Meridian

grid scale factor < 1

mapping projection

Earths

Surface

(Spheroid)

grid scale factor > 1

Figure 3.6

Variation of grid scalefactor across a

mapping grid

BP Amoco

Standard Practice

BP Amoco

Standard Practice


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structure

ref. point

drilling grid north

(DGN)

Structure Centred ReferencingSurvey Reference = True Northdrilling datum

(= rotary table)A

Well Centred ReferencingSurvey Reference = True North

DGN

B

Structure Centred ReferencingSurvey Reference = Grid NorthC

DGN

Well Centred ReferencingSurvey Reference = Grid NorthD

DGN

(MAPPING)GRID

NORTH

TRUENORTH

NorwaUK - FortiesUK - MagnusUK - former Amoco

UK - former BP excludin Forties, Ma nusNetherlands

USA - Gulf CoastUSA - LandColombia

USA - Alaska

Table 3.1

Definition of the

drilling grid in someBP Amoco operatingareas


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Survey Reference Direction

Drilling Grid Origin


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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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D


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I

F B

X Y Z

HX

F

Y

Z

True North

Figure 3.7

Components of themagnetic field vector


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Location Lat. Long. Declination DipAngle

FieldIntensity

HorizontalIntensity

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Table 3.2

The magnetic field insome of BP Amocosoperating areas(approximate valuesas of 1 July 1999)


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BP Amoco

Standard Practice


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2

f x( ) = 1

2exp

x ( )2

22


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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 +2-1 +1

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)

confidence

levelstandard

deviationsconfidence

levelstandard


levelstandard

deviations

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 dimensional

normal distribution

Table 3.3

Confidence intervals

for the one

dimensional normal

distribution


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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 +2-1 +1

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)

confidence

levelstandard


levelstandard


levelstandard

deviations

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 dimensional

normal distribution

Table 3.3

Confidence intervals

for the one

dimensional normal

distribution


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North

East

Figure 3.9

A two dimensional

distribution resolved

in two directions


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directionof maximum

variation

directionof minimumvariation

min

max

standarderrorellipse

North

East

90

max

min

confidence

level

standard

deviations

confidence

level

standard

deviations

confidence

level

standard

deviations

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


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For a fulldescription of the

method, see


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Propagation

Mode 1 2 3 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 B

contains a list of thecurrent BP Amocoapproved errormodels.


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Section A.2describes the

interpretation andmanipulation of

position covariancematrices.


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September 1999 Issue 1 Theory 3-29/30


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September 1999 Issue 1 Methods 4- i

Section 4

Contents

Page

4-1

4-6

4-17

4-27

4-34

4-39

4-40

4-48

4-55

4-59

Figure

4.1 A well planned development 4-3

4.2 A poorly planned development 4-5

4.3 Flowchart for survey program design 4-7

4.4 Schematic of a relief well 4-10
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4-ii Methods September 1999 Issue 1

Section 4

Contents (contd)

Figure Page

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

4.6 How a nearby offset well appears on a travelling cylinder 4-27

4.7 Travelling cylinder 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 drillers target 4-35

4.11 Calculation of the drillers target (contd.) 4-36

4.12 Effect of hole angle on size of drillers target (side-on view) 4-37

4.13 Drillers target volume for a horizontal well 4-38

4.14 Pinched-out drillers target a case for geosteering 4-39

4.15 In-hole referencing section drilled with multiple BHAs 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 Survey T-Plot 4-60
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September 1999 Issue 1 Methods 4-iii/iv

Section 4

Contents (contd)

Table Page

4.1 Required competencies for anti-collision work 4-19

4.2 Calculation of in-hole reference corrections section drilled with multiple BHAs 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, by region 4-58

4.5 Forbidden hole directions for axial magnetic interference

corrections 4-58

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

4.7 Quantitative 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 Instrument

Performance analyses 4-65
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September 1999 Issue 1 Methods 4- 1

Mathematical, logical and procedural

tools for optimum well positioning.


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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

Figure 4.2

A poorly planneddevelopment


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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.

Appendix Ccontains a Survey

Program Data Sheet,useful for inclusion in

the drilling program


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identify geological objectivestarget tolerances while drilling

maximum uncertainty ofdefinitive survey

select

survey

sequence

identify drilling objectivesanti-collision, economic target size

external magnetic interferencerelief well contingencyregulatory requirements

approvederror models

check

objectives

are met

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

check program

robustnesssufficient data redundancycontingency for tool failure

record in

drilling

program

well trajectory,casing program

specify program

detailsstation intervalsminimum depth rangesvalidation surveyscontingency surveys

standardrunning

procedures

JORPs arecovered in

Section 5.10

Figure 4.3

Flowchart for surveyprogram design


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last casing shoeabove reservoir

first approach

- above lastcasing shoe

second approach

- at kill point

cone of uncertaintyaround target well

Reliefwell

Targetwell

Figure 4.4

Schematic of arelief well


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2Absolute Uncertainty = [ (2surface uncertainty)

+ (2surface-to-seabed uncertainty)

+(2lateral wellbore uncertainty) ]

Example: Offshore well in 800m of water.

2surface uncertainty = 5m (typical of DGPS)2surface-to-seabed unc. = 8m*

2lateral wellbore unc. = 10m

2Absolute Uncertainty = [ 5 + 8 + 10 ] = 13.7m

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

Land and hydrographic surveyors will usually quote uncertainties at 2

standard deviations (2) by default. Check. In some high step-outdevelopment wells, the above criterion may not be practically achievable. A

dispensation may be justified on several grounds: Knowledge and/or depletion of the reservoir makes a blowout very

unlikely

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 survey

program


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BP Amoco



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

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).

LBL acousticsare described in

Section 3.1


7

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7

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N

d

S1(di)S2(di),SN(di).

d

( )

( ) ( ) ( )

S d

S d S d S d

equiv i

i i N i

= + + +

1 1 1

1

2

2

2 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.


7

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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 in

the hole.

The preciseinterpretation of this

rule for MWD surveysis described in

Section 5.2


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Sb

dd Sb

dd Sb


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Sb

lesser of :

a) 1% of drilled depthb) 10m

radius ofinterfering well

radius of

planned well

most likely positionof planned well3 error ellipse

3 error ellipse

most likely positionof interfering well

MINIM

UMALLOW

ABLESEPARATION

Figure 4.5

The minimumseparation rule for

major risk wells


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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 fordrill ahead decisions

Table 4.1

Requiredcompetencies foranti-collision work


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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.

The separations are considered as distances measured perpendicular to theplanned well, so that they lie in the plane of the anti-collision diagram. 3D orminimum 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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A nearby well presents a if a collision with it would

carry a significant risk to personnel or the environment. It

presents a if the risk to personnel and the

environment 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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Sb

Sb

Sb

Example: Planned well uncertainty at 1 std. dev. = 1= 8 mInterfering well uncertainty at 1 std. dev. = 2 = 5.5 mHole size in planned well = d1= 17.5" = 0.445 m

Casing OD in interfering well = d2= 13.375" = 0.340 m

Allowance for survey bias = Sb= 0 m

Drilled depth = DD = 650 m

Separation = 3(8+5.5) + (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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( )

22

1

2

1 2

1 2ln

d d

Rd d S

b

+

+ + +

1

2

2

2+

R

Example: 1, 2, d1, d2, Sb as aboveTolerable Collision Risk = R= 1 in 80 = 0.0125

= [8 + 5.5] = 9.71 mSeparation = 9.71{2 ln [ (0.445+0.340) / [(0.0125)(9.71)(2.51)] ] }

+(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

R

1 2

21

+


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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.

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 the

left 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.

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


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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 always

require a full rework of the anti-collision calculations.

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 whethereither the tolerance can be relaxed without violating any no-go areas (for

example 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.


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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 a

tolerance 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)


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2040

6080

992

20

20

40

40

60

0

40

197620 40

planned wellinterfering well

N

SE

W0

180

270 901000

2000

4000

2040

6080

3000

202910

3826

47795000

4779

9922910

38261976

For moreinformation on theTravelling Cylinderand its uses, see

Figure 4.6

How a nearby offsetwell appears on atravelling cylinder

BP Amoco

Standard Practice


88/

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BP AmocoStandard Practice


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2347

2370

Relative Bearing

= 96 deg

Radial Distance= 31 m

RelativeDepths

50

40

30

320

300

InterferingWell

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


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800

960

900

980

1000

800

9001000

1000

1000

800

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

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

scarcely be crossed without drilling

within 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

C

V

Figure 4.8

Rules andconventions for

drafting tolerancelines

The worksheet,plus 3 completed

examples, is inAppendix C.


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V/C

M F


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eletromagneticfield lines

well to beavoided

wire insidewell carrying

current I

conductorelectricallygrounded

w r

B

MWDsensors

well beingdrilled

For more on thepractical limitations of

QRA applied toanti-collision see

For moreinformation see

Figure 4.9

Principle of singlewire magnetic ranging


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B,

r

( )Br

r w=

0

2

2

I

w

r

( )rB

w B=

0

2

2

I


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95

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geological target

surveyed

well path

2 s.d. error ellipse

(a) (b)

apparent pointof penetration

Figure 4.10

Calculation of thedrillers target


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> 95%

90% - 95%

< 90%

well

direction

(c) (d)geological target

drillers target at95% confidence

inclusion probability

Figure 4.11

Calculation of thedrillers target (contd.)


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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

drillers target

amount of target truncated at front & back

= highside uncertainty / cos (incl)

Figure 4.12

Effect of holeangle on size ofdrillers target(side-on view)


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entry plane

exit (or TD)plane

geological target volumedrillers target volume

directionof well

The BP Amocoalgorithm and thegraphical methodare described in

Section A.4

Figure 4.13

Drillers target volumefor a horizontal well


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geological target volumepinched-out drillers target

directionof well

Figure 4.14

Pinched-out drillerstarget a case forgeosteering

The minimumcurvature equationsare given inSection A.1

BP AmocoStandard Practice


1

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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


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gyro multishotsurvey

in-hole reference

interval

IHR MWD surveys

MWD surveys

BHA #1

BHA #3

BHA #2 BHA #1

BHA #3

BHA #2

Figure 4.15

In-hole referencing section drilled with

multiple BHAs


1

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1

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MeasuredDepth

GyroAzimuth

MWDAzimuth

BHA # InterpolatedGyro

Azimuth

IHRCorrection

CorrectedMWD

Azimuth

1250 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

Table 4.2

Calculation of in-holereference corrections section drilled with

multiple BHAs


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gyro multishotsurvey

MWD surveys usedfor calculating IHR

correction

IHR correctedMWD surveys

MWD surveysrejected due to

external magneticinterference

Figure 4.16

In-hole referencing section drilled withsingle BHA


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MeasuredDepth

GyroAzimuth

MWDAzimuth

Interp.Gyro

Azimuth

AzimuthDiff.

IHRCorrection

CorrectedMWD

Azimuth

6200* 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


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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.


1

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Observatory

Measured Field

at Observatory

Calculated Field

at Wellsite

Mean Offset Derived

From Wellsite Survey

Wellsite

For a completediscussion of

interpolation in-fieldreferencing, see

and

Figure 4.17

The IIFR principle


1

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1

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Real time

(rig site)

Regularturn-around

(office)

Figure 4.18

Typical processsequence in an IIFRoperation


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OPTION 1 Correction for crustal field declination

OPTION 2 Correction for crustal field declination and

drillstring interference


1

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OPTION 3 Correction for tool sensor errors, field variation

and interference using near real-time data


1

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PermanentMagnetic

ObservatoryLogging

UnitDirectional

Engineers Office

Geomagnetic

Data Centre

IIFR Data

Processing Office

ObservatoryData (real-time)

Observatory Data (bulk)

IIFR ProcessedMWD surveys

RAW MWDsensor data

Figure 4.19

Typical data flow in anIIFR operation


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B

P z:

BP

zm =

4 2

Bm z


1

BP Amoco



z1 z2

P1

P2

Drill Collar Mud Motor BP

z

P

zax

= +

1

4

1

1

2

2

2

2

z1

z2

P1

P4

Drill Collar Mud Motor BP

z

P

z

P

z

P

zax

= + + +

1

4

1

1

2

2

2

2

3

3

2

4

4

2

Stab.

z3 z4

P3

P2

magneticsensors

magneticsensors

az

( ) ( ) azax

H

B

BInc Azi=

180

. .sin .sin

BH

Inc Azi

Figure 4.20

Estimating magneticaxial interference


1

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magnetic north(direction relative to

drillstring unknown)

B

apparent

magneticnorth

axial

interferencevector

(magnitude

unknown)

Bax

B + Bax

Problem

(3) and we know the

Earths 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

Figure 4.21

The principle ofsimple axialinterferencecorrections


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Drilling Area MaximumAcceptable

CorrectionGulf Coast, Middle East, Far East, Africa, South America, FSU 6

North Sea, Northern Europe, Canada, Norway 8

Alaska 10

Azimuth of Well Forbidden Inclination Range

Magnetic E or W 19or more no restriction

Magnetic E or W 18 87 93



Magnetic E or W 5or less 72 108

Table 4.4

Maximum acceptableaxial magnetic

interferencecorrections, by region

Table 4.5

Forbidden holedirections for axial

magnetic interferencecorrections


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The development

and validation ofINTEQs method isdescribed in


1

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Inclination

Azimuth

MD

5

30

25

20

15

10

40

35

315

340

335

330

325

320

350

345

500 2500200015001000

MWD

Gyro

Figure 4.22

A Survey T-Plot


1

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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 in

Section A.2

Table 4.6

Rules-of-thumb whenusing the error ellipsemethod


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Ratio (R) of

ellipse 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 that

ellipses willnot overlap

Table 4.7

Quantitativeinterpretation of theerror ellipse method


1

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1

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MD Comparisonsurvey

azimuth

Interpolatedreference survey

azimuth

Observedazimuth

difference

1 std.dev.azimuth

difference

Normalised azimuth

difference

(ft) survey 1 s.d. survey 1 s.d. (std dev.)

A B C D E = A - C F = B+C G = E / F

1349 135.7 0.78 136.61 0.35 -0.91 0.85 -1.06

1444 136.4 0.78 137.54 0.35 -1.14 0.85 -1.33

1538 136.9 0.79 137.81 0.36 -0.91 0.87 -1.05

1632 137.2 0.81 138.45 0.37 -1.25 0.89 -1.40

1727 136.9 0.82 138.59 0.37 -1.69 0.90 -1.88

1822 137.7 0.82 139.02 0.37 -1.32 0.90 -1.47

1916 138.9 0.83 139.66 0.38 -0.76 0.91 -0.83

2011 138.1 0.84 140.45 0.38 -2.35 0.92 -2.55

2106 139.5 0.84 140.73 0.38 -1.23 0.92 -1.33

2200 141.6 0.84 141.75 0.39 -0.15 0.93 -0.16

2294 141.6 0.85 142.18 0.40 -0.58 0.94 -0.62

2388 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


1

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September 1999 Issue 1 Methods 4- 65/66

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 RelativeInstrumentPerformance

analyses


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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

5-29

5-31

5-35

Figure

5.1 Sensor arrangement in Gyrodatas Wellbore Surveyor(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 survey probe 5-23
http://section5b.pdf/http://section5b.pdf/http://section5b.pdf/http://section5b.pdf/http://section5b.pdf/http://section5b.pdf/http://section5b.pdf/http://section5b.pdf/http://section5b.pdf/http://section5b.pdf/http://section5c.pdf/http://section5c.pdf/http://section5c.pdf/http://section5c.pdf/http://section5c.pdf/http://section5c.pdf/http://section5c.pdf/http://section5c.pdf/http://section5c.pdf/http://section5c.pdf/http://section5f.pdf/http://section5f.pdf/http://section5f.pdf/http://section5f.pdf/http://section5f.pdf/http://section5g.pdf/http://section5g.pdf/http://section5g.pdf/http://section5g.pdf/http://section5g.pdf/http://section5g.pdf/http://section5g.pdf/http://section5g.pdf/http://section5g.pdf/http://section5g.pdf/http://section5g.pdf/http://section5g.pdf/http://section5g.pdf/http://section5g.pdf/http://section5g.pdf/http://section5g.pdf/http://section5g.pdf/http://section5g.pdf/http://section5g.pdf/http://section5g.pdf/http://section5h.pdf/http://section5h.pdf/http://section5h.pdf/http://section5h.pdf/http://section5h.pdf/http://section5d.pdf/http://section5d.pdf/http://section5e.pdf/http://section5f.pdf/http://section5f.pdf/http://section5e.pdf/http://section5d.pdf/http://section5h.pdf/http://section5g.pdf/http://section5g.pdf/http://section5g.pdf/http://section5g.pdf/http://section5f.pdf/http://section5c.pdf/http://section5c.pdf/http://section5b.pdf/http://section5b.pdf/


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5-ii Survey Tools September 1999 Issue 1

Section 5

Contents (contd)

Table Page

5.1 Position uncertainty for inclination only surveys 5-2

5.2 Quality measures for electronic magnetic

multishot surveys (generic) 5-13

5.3 Quality measures common to all Gyrodata surveys 5-17

5.4 Quality measures for Gyrodata gyrocompassing surveys 5-18

5.5 Quality measures for Gyrodata continuous surveys 5-18

5.6 Quality measures for Keeper multishot surveys 5-21

5.7 Quality measures for RIGS surveys 5-24

5.8 JORPs documents currently in use 5-37
http://section5b.pdf/http://section5c.pdf/http://section5c.pdf/http://section5d.pdf/http://section5e.pdf/http://section5e.pdf/http://section5e.pdf/http://section5f.pdf/http://section5h.pdf/http://section5h.pdf/http://section5f.pdf/http://section5e.pdf/http://section5e.pdf/http://section5d.pdf/http://section5c.pdf/http://section5b.pdf/


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September 1999 Issue 1 Survey Tools 5-1

The surface and subsurface

instrumentation used in wellboresurveying.

Recommended Practices for tool selection and operation are

in italics.


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5-2 Survey Tools September 1999 Issue 1

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

Average

Measured

Inclination

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


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TOTCO

TOTCO

TOTCO

Teledrift Anderdrift


1

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1

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

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

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


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Each MWD tool must pass a comparison with external data.

CHECK SHOTS

Section A.3contains details of

how to calculatethese quantities


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

ELECTRONIC MULTISHOT

MULTI-STATION DATA ANALYSIS


1

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1

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


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TOTCO

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.

MWDnon-magnetic spacing

requirements are

in Section 4.9


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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

Latitude

Table 5.2

Quality measures forelectronic magneticmultishot surveys

(generic)


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Wellbore Surveyor GWS Battery/Memory RGS-BT RGS-CT

Wellbore Surveyor

Continuous

Battery/Memory


1

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accelerometer(non-rotating)

Universaljoints

exciter/pick-off coils

torquercoils

gyroscope(rotating)

magnet assembly

for torquer coilsto force against

motor/statorand bearingassembly

Wellbore SurveyorBattery/Memory Continuous

Figure 5.1

Sensor arrangementin GyrodatasWellbore Surveyor(large diameter tool)


1

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1

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Battery/Memory

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


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QA measure Tolerance Failure may

indicate

Possible cause(s) of

failureSingle station test Earth rate

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

noisy data reinitialisedeeper

Single station test gyro drift & noise

mean


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BP Amoco



Keeper Finder

Zener Sub

Keeper Gyro

Cablehead

Decentraliser

Casing Collar

Locator

Gamma Sensor

Temperature

Sensor

Decentraliser

Pressure Barrel

/Heatshield

6.35 m

/ 21 ftFigure 5.2

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


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BP Amoco




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BP Amoco



QA measure Tolerance Failure mayindicate

Possible cause(s) offailure

Field calibration

mass unbalance

DI < 0.6/hr

DS < 1.0/hr

poor initial azimuth

reference

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


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BP Amoco




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BP Amoco



PressureBarrel

Electronics

Gyro/

Accelerometers

BreechLock

CableHead

RollerCentraliser

RollerCentraliser

Figure 5.3

The RIGS surveyprobe


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BP Amoco



QA measure Tolerance Failure indicates Possible cause(s) offailure

Alignmentsummary

< 0.1 Noisy Alignment Excessive electricalnoise

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.

Table 5.7

Quality measures forRIGS surveys


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BP Amoco



Camera-based magnetic multishots are not a recommendedtool type.

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


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BP Amoco



SRGs must not be used:

For multishot surveys

Deeper than 450m/1500ft below rotary table

In hole inclinations greater than 10

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


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BP Amoco



Surface references must be established and checked by a

qualified 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.


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BP Amoco



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.


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BP Amoco



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

Finder Keeper Keepers

Finder Keeper


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BP Amoco



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


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BP Amoco



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


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BP Amoco



FINDS

Battery/Memory Keeper


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BP Amoco




1

September1999

Issue1

SurveyTools5-37/

38

ServiceCompany

JORPs document Tool Coverage

MWD Inertialgyro

North-seeking

gyro

Surfaceread-out

gyro

Camera-basedgyro

EMS Camera-based

magnetic

Teledrift

Anadrill Anadrill MWD SurveyingProcedures Manual*

Baker Hughes

INTEQ

JORPs for Directional

MWD

BPX and BHI JORPs

Halliburton /Sperry-Sun

JORPs for SSDSDirectional MWD*

Surface ReadoutGyroscope Operationsfor BPX

Gyrodata BP JORPs Manual*

Scientific Drilling BP JORPs*

Under revision at time of writing

Table 5.8 JORPs documents currently in use


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BP Amoco


September 1999 Issue 1 Technical Integrity 6-i/ii

Section 6

Contents

Page

6-1

6-2

6-6

6-8

6-20

6-22

6-29

Figure

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

Table

6.1 Generic classification of potential failures in thedirectional and survey process 6-5
http://section6b.pdf/http://section6b.pdf/http://section6b.pdf/http://section6b.pdf/http://section6b.pdf/http://section6b.pdf/http://section6b.pdf/http://section6b.pdf/http://section6b.pdf/http://section6b.pdf/http://section6b.pdf/http://section6b.pdf/http://section6c.pdf/http://section6c.pdf/http://section6c.pdf/http://section6c.pdf/http://section6c.pdf/http://section6c.pdf/http://section6c.pdf/http://section6c.pdf/http://section6c.pdf/http://section6c.pdf/http://section6c.pdf/http://section6c.pdf/http://section6e.pdf/http://section6e.pdf/http://section6e.pdf/http://section6e.pdf/http://section6e.pdf/http://section6e.pdf/http://section6e.pdf/http://section6e.pdf/http://section6e.pdf/http://section6e.pdf/http://section6e.pdf/http://section6e.pdf/http://section6f.pdf/http://section6f.pdf/http://section6f.pdf/http://section6f.pdf/http://section6f.pdf/http://section6f.pdf/http://section6b.pdf/http://section6b.pdf/http://section6b.pdf/http://section6c.pdf/http://section6c.pdf/http://section6c.pdf/http://section6c.pdf/http://section6b.pdf/http://section6f.pdf/http://section6e.pdf/http://section6e.pdf/http://section6c.pdf/http://section6c.pdf/http://section6b.pdf/http://section6b.pdf/


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BP Amoco


September 1999 Issue 1 Technical Integrity 6-1

How to minimise the risk of a gross

well positioning error and establish anauditable trail from target definition to

definitive survey.


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BP Amoco


6-2 Technical Integrity September 1999 Issue 1


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BP Amoco

Directional Survey

amoco - directional survey handbook

Documents

survey tools5

survey calculation4

bp amoco organisation

survey data comparisonhttp

survey data management6

survey program design4

directional design6

bp amocobpad