BPA-D-003 Tubular Design Manual
Issue 3 Uncontrolled Copy September 1999 Revised January 2000 Revised December 2008
Prepared by
BP EPT Integrity Management Team
Approved by
S. K. Sigurdson, VP, Drilling and Completion Engineering
Approved by
M. L. Payne, SETA, Casing and Tubing Design
Date
December 30, 2008
Revision
2.0
Intellectual Property and Confidentiality Notice c
2008 BP America Inc. All rights reserved. This document contains confidential information, which is the exclusive property of BP America, Inc. In whole or part, this document or its attachments MAY NOT be reproduced by any means, disclosed or used for any purpose without the express written permission of BP America Inc.
BPA-D-003 October 2008 Issue 3
2
BP Confidential
Contents I
Overview and Policies
1
1 Overview 1.1
3
Objective . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
3
2 Policy
5
2.1
Deviations from Policy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
5
2.1.1
SPU Deviations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
5
2.1.2
Segment Deviations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
6
2.1.3
Deviation Management . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
6
II
Quick Guide
7
3 Quick Guide 3.1 3.2
9
Data Needed Before Design . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
9
Design Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
10
3.2.1
Installation Loads . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
10
3.2.1.1
Casing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
10
3.2.1.2
Tubing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
11
3.2.2
Drilling Load Cases (Casing) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
12
3.2.3
Production Load Cases (Casing) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
12
3.2.4
Production Load Cases (Tubing) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
12
3.2.5
Casing Setting Depths . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
13
3.2.6
Collapse Design . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
13
3.2.7
Burst Design . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
14
3.2.8
Tension Design . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
14
3.2.8.1
Running (Casing or Tubing) . . . . . . . . . . . . . . . . . . . . . . . . . . .
14
3.2.8.2
Cementing (Casing) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
14
3.2.8.3
Initial Condition (Casing or Tubing) . . . . . . . . . . . . . . . . . . . . . . .
14
3.2.8.4
Drilling and Production (Casing or Tubing) . . . . . . . . . . . . . . . . . . .
15
Triaxial Design . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
15
3.2.9
3.2.10 Buckling and Compression EPT Drilling
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . i
16
BP Confidential
III
3.2.10.1 Effective Force . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
16
3.2.10.2 Critical Effective Force for Sinusoidal Buckling . . . . . . . . . . . . . . . . .
16
3.2.10.3 Post-Buckled Geometry . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
16
3.2.10.4 Mitigating Buckling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
17
3.2.11 Casing Wear . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
17
3.2.11.1 Design Rules . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
17
3.2.12 Temperature . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
18
3.2.12.1 Drilling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
19
3.2.12.2 Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
20
3.2.12.3 Bullhead Kill . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
21
3.2.12.4 Long Term Water Injection . . . . . . . . . . . . . . . . . . . . . . . . . . . .
21
3.2.13 Special Design Cases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
21
3.2.14 Reliability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
22
3.2.15 Connection Selection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
22
3.2.16 Material Selection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
22
3.2.17 Minimum Design Factors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
22
3.2.18 Table Entries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
22
Detailed Manual
27
4 Introduction
29
4.1
Purpose . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
29
4.2
Procedure for Revision or Addition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
29
4.3
How to use this Manual . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
29
4.4
Definitions and Symbols . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
30
4.4.1
Well Categories . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
30
4.4.2
Glossary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
30
4.4.3
Symbols . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
37
4.4.4
Units and Conversions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
45
5 Data Needed Before Design
49
5.1
Functional Well Specification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
49
5.2
Pre-Drill Data Package . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
51
6 Tubular Design Software in BP 6.0.1 6.1 6.2
53
Safety Critical Software . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
53
Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
53
The Software Packages . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
54
6.2.1
CasingSeat . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
54
6.2.2
StressCheck . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
54
6.2.2.1
54
EPT Drilling
Temperature Calculation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ii
BP Confidential
6.2.3 6.2.4 6.3
6.2.2.2
Complex Designs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
55
6.2.2.3
Annular Fluid Expansion Analysis . . . . . . . . . . . . . . . . . . . . . . . .
56
6.2.2.4
Wellhead Movement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
56
6.2.2.5
Friction Effects . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
56
6.2.2.6
Connections . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
57
6.2.2.7
Material Selection for Sour Service . . . . . . . . . . . . . . . . . . . . . . . .
57
WellCat . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
57
6.2.3.1
Tubing Design with WellCat . . . . . . . . . . . . . . . . . . . . . . . . . . .
57
CWear . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
57
Using the Software . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
58
6.3.1
CasingSeat . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
58
6.3.2
StressCheck . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
58
6.3.2.1
Design and Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
58
6.3.2.2
The BP Template . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
59
Input Guidelines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
59
6.3.2.3
6.3.2.3.1
File . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
59
6.3.2.3.2
Edit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
62
6.3.2.3.3
Wellbore . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
63
6.3.2.3.4
Tubular . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
64
6.3.2.3.5
View . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
67
6.3.2.3.6
Tools . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
68
6.3.2.3.7
Window . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
68
6.3.2.3.8
Help . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
69
Design Assumptions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
69
WellCat . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
70
6.3.3.1
70
6.3.2.4 6.3.3
6.3.4
6.4
Structure of WellCat . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.3.3.1.1
Inventories . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
72
6.3.3.1.2
Wellbore . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
80
6.3.3.1.3
Loads . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
83
CWear . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
85
6.3.4.1
Tortuosity (Survey Tab) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
86
6.3.4.2
Dogleg Insertion (Survey Data) . . . . . . . . . . . . . . . . . . . . . . . . . .
86
6.3.4.3
Drill Pipe Protector Calculation (Drill String Tab) . . . . . . . . . . . . . . .
86
6.3.4.4
Revised Burst and Collapse Resistance (Parameter Data) . . . . . . . . . . .
87
Wear and Casing Design Software . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
87
6.4.1
Wear in Directional Wellbores . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
88
6.4.2
Wear in Vertical Wellbores . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
88
7 Casing Setting Depth Guidelines
91
7.1
Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
91
7.2
Why Casing? . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
91
EPT Drilling
iii
BP Confidential
7.3
7.2.1
Rock is Permeable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
91
7.2.2
Rock is Weak . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
92
7.2.3
Rock is Chemically Active . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
92
General Casing Setting Depth Guidelines . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
92
7.3.1
Example Problem . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
96
7.3.1.1
Plot Upper and Lower Drilling Fluid Limits with Margins . . . . . . . . . . .
97
7.3.1.2
Determine Initial Requirements for Wellbore Integrity . . . . . . . . . . . . .
97
7.3.1.3
Check for the Possibility of Differential Sticking . . . . . . . . . . . . . . . .
99
7.3.1.4
Check Formation Constitution . . . . . . . . . . . . . . . . . . . . . . . . . . 101
7.3.1.5
Final Results . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 101
7.3.2
Structural Conductor Casing Setting Depths . . . . . . . . . . . . . . . . . . . . . . . 101
7.3.3
Conductor Casing Setting Depths
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 101
7.3.3.1
Effective Mud Weight . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 102
7.3.3.2
Equivalent Circulating Density (ECD) . . . . . . . . . . . . . . . . . . . . . . 103
7.3.3.3
Annular Pressure Loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 104
7.3.3.4
Hammers and Geotechnical Data . . . . . . . . . . . . . . . . . . . . . . . . . 104
7.4
Estimation of Fracture Gradient . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 106
7.5
Casing Depth Selection Guide–North Sea . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 109
7.6
7.5.1
Structural (Conductor) Setting Depth . . . . . . . . . . . . . . . . . . . . . . . . . . . 109
7.5.2
Conductor or Surface Casing Setting Depth . . . . . . . . . . . . . . . . . . . . . . . . 110
7.5.3
Casing Setting Depths for HPHT Wells . . . . . . . . . . . . . . . . . . . . . . . . . . 110
Casing Depth Selection Guide - Gulf of Mexico . . . . . . . . . . . . . . . . . . . . . . . . . . 111 7.6.1
7.6.2 7.7
7.8
Gulf of Mexico Operations in WD < 2,500 ft. . . . . . . . . . . . . . . . . . . . . . . . 111 7.6.1.1
General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 111
7.6.1.2
Jackup Structural Conductors . . . . . . . . . . . . . . . . . . . . . . . . . . 111
7.6.1.3
Semi-submersible Structural Conductors . . . . . . . . . . . . . . . . . . . . 112
7.6.1.4
Platform Structural Conductors . . . . . . . . . . . . . . . . . . . . . . . . . 112
Gulf of Mexico Operations in WD > 2,500 ft. . . . . . . . . . . . . . . . . . . . . . . . 113
Keathley Canyon 255 No. 1 Example . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 115 7.7.1
30 in. Structural Pipe–6,123 ft. BRT . . . . . . . . . . . . . . . . . . . . . . . . . . . . 115
7.7.2
20 in. Surface Casing–7,880 ft. BRT . . . . . . . . . . . . . . . . . . . . . . . . . . . . 116
7.7.3
16 in. Liner–9,850 ft. BRT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 116
7.7.4
13-3/8 in. Casing–11,200 ft. BRT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 116
7.7.5
11-3/4 in. Liner–13,100 ft. BRT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 116
7.7.6
9-5/8 in. Casing–17,200 ft. BRT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 116
7.7.7
7 in. Liner–21,000 ft. BRT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 116
Sizing Tubulars . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 117 7.8.1
Production Tubing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 117
7.8.2
Production Casing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 117
7.8.3
Intermediate and Surface Casing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 118
EPT Drilling
iv
BP Confidential
8 Collapse Design Criteria
123
8.1
Design Issues for Collapse . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 123
8.2
Calculating Collapse Pressure Design Factors . . . . . . . . . . . . . . . . . . . . . . . . . . . 124
8.3
Installation Loads
8.4
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 124
8.3.1
Casing Installation (Cementing) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 125
8.3.2
Tubing Installation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 127
Post-Installation Collapse Loads . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 127 8.4.1
Conductor Casing (Exploration and Development) . . . . . . . . . . . . . . . . . . . . 127 8.4.1.1
Surface Casing (Development) . . . . . . . . . . . . . . . . . . . . . . . . . . 129
8.4.1.2
Surface Casing (Exploration) . . . . . . . . . . . . . . . . . . . . . . . . . . . 130
8.4.1.3
Intermediate Casing/Liners . . . . . . . . . . . . . . . . . . . . . . . . . . . . 130
8.4.1.4
Production Casing, Liners and Tiebacks . . . . . . . . . . . . . . . . . . . . . 130
8.4.1.5
8.4.2
8.4.1.4.1
Above the Packer . . . . . . . . . . . . . . . . . . . . . . . . . . . . 130
8.4.1.4.2
Below the Packer . . . . . . . . . . . . . . . . . . . . . . . . . . . . 132
Production Tubing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 132 8.4.1.5.1
Low Internal Pressures . . . . . . . . . . . . . . . . . . . . . . . . . 132
8.4.1.5.2
High “A” Annulus Pressure . . . . . . . . . . . . . . . . . . . . . . . 133
Determining the Appropriate Collapse Rating . . . . . . . . . . . . . . . . . . . . . . . 133 8.4.2.1
Uniform Loading . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 134 8.4.2.1.1
8.4.2.2
8.4.2.2.1 8.4.3
Example Problem . . . . . . . . . . . . . . . . . . . . . . . . . . . . 137
Non-Uniform Loading . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 137 Drilling Recommendations . . . . . . . . . . . . . . . . . . . . . . . 139
High Collapse Casing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 141
9 Burst Design Criteria
143
9.1
Design Issues for Internal Pressure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 143
9.2
Calculating Internal Yield Pressure Design Factors . . . . . . . . . . . . . . . . . . . . . . . . 145
9.3
Installation Loads
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 146
9.3.1
Running . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 146
9.3.2
Casing Installation (Cementing) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 146
9.3.3
9.3.2.1
Cement Displacement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 146
9.3.2.2
Bumping the Plug . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 146
Tubing Installation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 148
9.4
External Pressure Profiles for Casing Post-Installation Loads . . . . . . . . . . . . . . . . . . 148
9.5
Post-Installation Casing Burst Loads . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 148 9.5.1
Conductor Casing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 149
9.5.2
Surface Casing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 149 9.5.2.1
Pressure Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 149
9.5.2.2
Well Control . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 150
9.5.3
Intermediate Casing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 150
9.5.4
Production Casing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 150
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9.5.4.1
Pressure Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 150
9.5.4.2
Completion Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 151
9.5.4.3
Tubing Leak . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 151
9.5.4.4
Drill Stem Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 152
9.6
External Pressure Profiles for Tubing Post-Installation Loads . . . . . . . . . . . . . . . . . . 153
9.7
Post-Installation Tubing Burst Loads . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 153 9.7.0.5
Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 153
9.7.0.6
Gas Lift . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 154
9.7.0.7
Injection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 154
9.7.0.8
Stimulation, Transient Loads . . . . . . . . . . . . . . . . . . . . . . . . . . . 154
10 Tensile Design Criteria
155
10.1 Tensile Design Parameters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 155 10.2 Axial Force Components . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 156 10.2.1 Fwt –Weight of Tubular in Air . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 157 10.2.2 Fbuoy –Buoyancy Effect . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 158 10.2.3 Fb –Tension Force from Bending . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 160 10.2.4 Fplug –Surface Pressure to Bump Plug . . . . . . . . . . . . . . . . . . . . . . . . . . . 160 10.2.5 Fl –Landing Force . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 161 10.2.6 Fop –Overpull . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 161 10.2.7 Fbal –Tensile Force from Change in Pressure or Fluid Density . . . . . . . . . . . . . . 161 10.2.8 FT –Tensile Force from Change in Temperature . . . . . . . . . . . . . . . . . . . . . . 162 10.2.9 Ff r –Tensile Force Due to Fluid Friction . . . . . . . . . . . . . . . . . . . . . . . . . . 163 10.2.10 Fshock –Shock Loads . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 164 10.2.11 Fpkr - Packer Force . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 164 10.3 Installation Tensile Force Calculations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 164 10.3.1 Running Casing or Tubing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 165 10.3.2 Cementing Casing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 165 10.4 Initial Conditions (Base Case) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 166 10.5 Drilling and Production Tensile Force Calculations . . . . . . . . . . . . . . . . . . . . . . . . 166 10.6 Tubing Tensile Design . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 166 10.6.1 Expansion Devices . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 167 10.6.2 Tubing Load Cases for Axial Loads . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 167 10.6.3 Length Changes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 168 10.7 Tensile Force Check for Buckling Analysis Requirements . . . . . . . . . . . . . . . . . . . . . 169 11 Triaxial Design Analysis
171
11.1 Triaxial Design Statement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 171 11.2 Von Mises Equivalent (VME) Stress . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 171 11.3 Triaxial Calculation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 173 11.3.1 Total Axial Stress Calculations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 173 EPT Drilling
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11.3.2 Radial and Circumferential Stress Calculation . . . . . . . . . . . . . . . . . . . . . . . 174 11.3.3 Triaxial Stress Safety Factor Calculation . . . . . . . . . . . . . . . . . . . . . . . . . . 175 11.4 Example Problem . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 175 12 Buckling and Compression Design Considerations
177
12.1 Buckling Design Considerations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 177 12.2 Effective Tension . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 178 12.2.1 Example Problem - Effective Tension . . . . . . . . . . . . . . . . . . . . . . . . . . . . 179 12.2.2 Buckling in a Vertical Wellbore . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 180 12.2.3 Buckling in an Inclined Wellbore . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 180 12.2.4 Buckling in a Curved Wellbore . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 181 12.3 Permanent Corkscrewing (Yield) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 181 12.3.1 Tool Free Passage Length . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 184 12.3.2 Reduction of Helical Buckling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 184 12.3.3 Example Buckling Problem . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 184 13 Casing Wear
187
13.1 Parameters for Casing Wear . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 187 13.2 Predicting Casing Wear . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 189 13.2.1 Contact Pressure vs. Load . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 190 13.2.2 Well Design Guidelines
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 192
13.2.3 Doglegs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 193 13.2.4 Estimation of Casing Wear . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 193 13.2.4.1 Information Required . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 194 13.2.4.2 Procedure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 194 13.2.4.3 Interpretation of Results . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 195 13.2.4.4 Example . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 196 13.3 Casing Rating Calculations for Worn Casing . . . . . . . . . . . . . . . . . . . . . . . . . . . . 196 13.3.1 Internal Yield Pressure
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 196
13.3.2 Collapse . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 197 13.4 Considerations to Minimize Casing Wear . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 197 13.4.1 Casing Material . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 201 13.4.2 Crossovers (Including Centralizers and Cementing) . . . . . . . . . . . . . . . . . . . . 201 13.4.3 Tapered Casing Strings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 202 13.4.4 Hard-banding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 203 13.4.5 Drill Pipe Protectors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 204 13.4.5.1 Rotating Drill Pipe Protectors . . . . . . . . . . . . . . . . . . . . . . . . . . 205 13.4.5.2 Non-Rotating Drill Pipe Protectors . . . . . . . . . . . . . . . . . . . . . . . 206 13.4.6 Mud Types . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 206 13.5 Measuring/ Monitoring Casing Wear . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 207 13.5.1 Mechanical . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 207 EPT Drilling
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13.5.2 Acoustic (Preferred) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 207 13.5.3 Electromagnetic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 207 13.5.4 Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 208 13.6 Design Imperatives for Casing Wear . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 208 14 Temperature Considerations
211
14.1 Temperature Issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 211 14.2 Static Temperature Profile . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 212 14.2.1 Example Calculation of Static (Undisturbed) Temperature Profile . . . . . . . . . . . 214 14.3 Cementing Temperature Profile . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 214 14.3.1 Example Calculation of Cementing Temperature Profile . . . . . . . . . . . . . . . . . 215 14.4 Drilling Temperatures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 216 14.5 Production Temperatures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 217 14.5.1 Example Calculation of Drilling and Producing Temperature Profiles . . . . . . . . . . 218 14.6 Miscellaneous Temperature Profiles . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 218 14.6.1 Bullheading . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 218 14.6.2 Long Term Water or Gas Injection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 219 14.7 Yield Stress Derating . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 221 15 Special Design Cases
225
15.1 Jackup Structural Conductor Design Guidelines . . . . . . . . . . . . . . . . . . . . . . . . . . 225 15.1.1 Loads . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 225 15.1.2 Environmental Conditions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 226 15.1.3 Fatigue Due to Cyclic Wave Loading . . . . . . . . . . . . . . . . . . . . . . . . . . . . 226 15.1.4 Vortex Induced Vibration Fatigue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 227 15.1.5 Detailed Design Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 227 15.1.6 Design Selection Procedure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 229 15.2 Annulus Pressure Build-up Due to Temperature . . . . . . . . . . . . . . . . . . . . . . . . . . 231 15.2.1 APB Calculation and Mitigation Guidelines . . . . . . . . . . . . . . . . . . . . . . . . 231 15.2.2 Demonstration of Fundamental APB Mechanism . . . . . . . . . . . . . . . . . . . . . 233 15.2.3 Example . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 235 15.2.4 APB Mitigation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 236 15.2.4.1 Nitrified Foam Spacer . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 236 15.2.4.1.1 Benefits of a Nitrogen Cushion . . . . . . . . . . . . . . . . . . . . . 237 15.2.4.1.2 Mud Removal and Channeling during Placement . . . . . . . . . . . 240 15.2.4.1.3 Foam Stability and Testing . . . . . . . . . . . . . . . . . . . . . . . 240 15.2.4.1.4 Gas Mitration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 242 15.2.4.1.5 Risks of Nitrogen Placement . . . . . . . . . . . . . . . . . . . . . . 243 15.2.4.1.6 Calculation Procedures . . . . . . . . . . . . . . . . . . . . . . . . . 243
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15.2.4.1.6.1
Gas Migration Calculations . . . . . . . . . . . . . . . . . . . 244
15.2.4.1.6.2
Alternate Post-Installation Scenarios . . . . . . . . . . . . . . 246 viii
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15.2.4.2 Rupture Disks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 246 15.2.4.2.1 Relation to APB . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 246 15.2.4.2.2 Rupture Disk Technology . . . . . . . . . . . . . . . . . . . . . . . . 248 15.2.4.2.3 Testing for Downhole Application - Outward-acting Rupture Disks . 249 15.2.4.2.4 Testing for Downhole Application - Inward-acting Rupture Disks . . 251 15.2.4.2.5 Summary of Testing for Downhole Application . . . . . . . . . . . . 252 15.2.4.2.6 Test of Cemented Disks . . . . . . . . . . . . . . . . . . . . . . . . . 252 15.2.4.2.7 Available Rupture Disks . . . . . . . . . . . . . . . . . . . . . . . . 253 15.2.4.2.8 Rupture Disk Selection and Specification . . . . . . . . . . . . . . . 253 15.2.4.2.8.1
Pressure and Temperature Selection . . . . . . . . . . . . . . 253
15.2.4.2.8.2
Seals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 254
15.2.4.2.8.3
Field Application . . . . . . . . . . . . . . . . . . . . . . . . . 256
15.2.4.2.8.4
Ordering and Quality Assurance . . . . . . . . . . . . . . . . 256
15.2.4.3 Syntactic Foam
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 256
15.2.4.3.1 Crush Pressure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 259 15.2.4.3.2 Volumetric Strain Rate . . . . . . . . . . . . . . . . . . . . . . . . . 260 15.2.4.3.3 Design, Performance and Selection of Syntactic Foam Modules . . . 260 15.2.4.3.3.1
Service Life and Design Basis . . . . . . . . . . . . . . . . . . 261
15.2.4.3.3.2
Size and Volume Calculations . . . . . . . . . . . . . . . . . . 262
15.2.4.3.3.3
Determination of Crush Pressure and Temperature . . . . . . 262
15.2.4.3.4 Operational Issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . 264 15.2.4.3.5 Transportation, Running and Installation . . . . . . . . . . . . . . . 264 15.3 Subsea Tieback Design . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 264 15.3.1 Design Issues Overview - Description of a Tieback . . . . . . . . . . . . . . . . . . . . 266 15.3.2 Problems to be Resolved during Design . . . . . . . . . . . . . . . . . . . . . . . . . . 266 15.3.3 The Drilling/Structural Engineering Interface . . . . . . . . . . . . . . . . . . . . . . . 269 15.3.4 Operational Aspects . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 269 15.3.5 Loadings on Tiebacks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 270 15.3.5.1 Environmental . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 270 15.3.5.2 Service Life . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 271 15.3.5.2.1 Water Injection Wells . . . . . . . . . . . . . . . . . . . . . . . . . . 271 15.3.5.2.2 Production Wells . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 271 15.3.5.2.3 Fatigue due to Service Life Loads . . . . . . . . . . . . . . . . . . . 272 15.3.5.2.4 Temperature Distributions . . . . . . . . . . . . . . . . . . . . . . . 272 15.3.6 Installation Sequence . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 272 15.3.7 Initial Design . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 274 15.3.7.1 Thermal Growth . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 274 15.3.7.1.1 Discussion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 275 15.3.7.2 Pressure Effects . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 276 15.3.7.2.1 Buckling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 276 15.3.7.2.2 Pre-tensioning . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 277 EPT Drilling
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15.3.8 Guidance on Heat Shrink Sleeve Installation . . . . . . . . . . . . . . . . . . . . . . . . 277 15.3.9 Example Calculation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 278 15.3.9.1 Input Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 278 15.3.9.2 Calculation–Structural Stiffness . . . . . . . . . . . . . . . . . . . . . . . . . 278 15.3.9.3 Calculation–Fixed End Action . . . . . . . . . . . . . . . . . . . . . . . . . . 278 15.3.9.4 Calculation–Pressure End Force . . . . . . . . . . . . . . . . . . . . . . . . . 279 15.3.9.5 Calculation–Displacement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 279 15.3.9.6 Calculation–Casing Forces . . . . . . . . . . . . . . . . . . . . . . . . . . . . 279 15.4 Wellhead Loads . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 279 15.5 Cuttings Re-injection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 281 15.5.1 Description of Cuttings Re-injection . . . . . . . . . . . . . . . . . . . . . . . . . . . . 282 15.5.2 Features Required in a Design
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 282
15.5.3 Erosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 282 15.5.3.1 Wellhead Erosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 282 15.5.3.2 Re-injection Point Erosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . 283 15.5.3.3 Annular Casing Erosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 285 15.5.4 Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 286 15.5.4.1 Use of De-aerated Seawater . . . . . . . . . . . . . . . . . . . . . . . . . . . . 286 15.5.4.2 Raw Seawater . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 287 15.5.5 Cementing
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 287
15.5.5.1 Location of the Shoe . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 288 15.5.5.2 Centralization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 288 15.5.5.3 Pipe Movement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 289 15.5.5.4 Spacers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 289 15.5.5.5 Tops of Cement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 289 15.5.5.6 Cement Mixing, Density and Volume . . . . . . . . . . . . . . . . . . . . . . 290 15.5.5.7 Cement Sampling and Testing . . . . . . . . . . . . . . . . . . . . . . . . . . 290 15.5.5.8 Contingencies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 291 15.5.5.9 Special Cases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 291 15.5.6 Annular Clearance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 291 15.5.7 Burst and Collapse . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 292 15.5.8 Seal Integrity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 295 15.6 Casing and Tubing Machined Crossover Design Guidance . . . . . . . . . . . . . . . . . . . . 296 15.6.1 Excessive Stress
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 296
15.6.2 Non-Uniform Material Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 296 15.6.3 Incorrect Connection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 296 15.6.4 Stress Concentrations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 296 15.6.5 Fatigue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 297 15.6.6 Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 297 15.6.7 Material and Geometry Vulnerable to Abrasion . . . . . . . . . . . . . . . . . . . . . . 297 15.6.8 Component Weakened by Pre-use . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 297 EPT Drilling
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15.6.9 Design Control . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 297 16 Tubular Design Reliability
299
16.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 299 16.2 Working Stress Design . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 299 16.3 Probabilistic Design . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 300 16.4 Comparison of Working Stress and Probabilistic Approaches . . . . . . . . . . . . . . . . . . . 302 16.4.1 Similarities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 302 16.4.2 Differences . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 302 16.4.3 Hybrid Approaches . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 302 16.5 Probabilistic Description of Performance Properties . . . . . . . . . . . . . . . . . . . . . . . . 303 16.5.1 Performance Properties by the Direct Method . . . . . . . . . . . . . . . . . . . . . . . 303 16.5.2 Collapse Rating for Small Datasets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 303 16.5.3 Performance Properties by the Indirect Method . . . . . . . . . . . . . . . . . . . . . . 304 17 Connections
309
17.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 309 17.2 Tensile Efficiency . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 309 17.2.1 Upsets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 310 17.2.2 Low and Negative Angle Load Flanks . . . . . . . . . . . . . . . . . . . . . . . . . . . 310 17.3 Leak Resistance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 313 R 17.3.1 Teflon Ring . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 314
17.3.2 Metal-to-metal Seals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 315 17.3.3 BP Classes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 315 17.4 Internal Stresses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 317 17.4.1 Cylindrical Threads . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 317 17.4.2 Torque Shoulder . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 317 17.5 Internal Profile . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 318 17.6 Multidimensional Loading . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 318 17.7 Families of Connections . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 321 17.7.1 API 8 Round (ST&C, LT&C, EUE and NUE) . . . . . . . . . . . . . . . . . . . . . . 321 17.7.2 API Buttress . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 321 17.7.3 Metal-to-Metal Seal, Threaded and Coupled . . . . . . . . . . . . . . . . . . . . . . . . 322 17.7.4 Metal-to-Metal Seal, Upset and Integral (or Coupled) . . . . . . . . . . . . . . . . . . 322 17.7.5 Metal-to-metal Seal, Formed and Integral (Semi-flush and Flush) . . . . . . . . . . . . 323 17.7.6 Weld On
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 323
17.8 Approved Connection List . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 323 17.9 Connection Selection Decision Tree . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 325 EPT Drilling
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18 Material Selection and Corrosion Guidelines
331
18.1 Scope . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 331 18.2 Material Selection Process . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 331 18.2.1 Casing Exposed to Muds and Brines . . . . . . . . . . . . . . . . . . . . . . . . . . . . 332 18.2.1.1 Sour-service Exposed to Produced Fluids . . . . . . . . . . . . . . . . . . . . 332 18.2.1.2 NACE Standard MR-0175 or ISO 15156 “Standard Approach” . . . . . . . . 335 18.2.1.3 BP NACE or ISO 15156 “Qualifying Materials for Specific Conditions” . . . 336 18.3 Internal Corrosion Control . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 337 18.3.1 Drilling Operations (Exploration/Appraisal Wells) . . . . . . . . . . . . . . . . . . . . 337 18.3.2 Production Operations (Development Wells) . . . . . . . . . . . . . . . . . . . . . . . 340 18.3.2.1 Corrosion Control in Completion Fluids . . . . . . . . . . . . . . . . . . . . . 341 18.3.2.1.1 Biocide . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 341 18.3.2.1.2 Oxygen Scavenger . . . . . . . . . . . . . . . . . . . . . . . . . . . . 342 18.3.2.1.3 Corrosion Inhibitor . . . . . . . . . . . . . . . . . . . . . . . . . . . 343 18.3.2.1.4 Scale Inhibitor . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 343 18.4 External Casing Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 343 18.5 Corrosion Background . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 344 18.5.1 Corrosion Mechanisms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 345 18.5.1.1 Carbon Dioxide . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 345 18.5.1.2 Hydrogen Sulfide . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 346 18.5.1.3 Oxygen . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 346 18.5.1.4 Halide Ions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 347 18.5.1.5 Galvanic Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 347 18.5.1.6 Localized Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 347 19 Kick Tolerance
349
19.1 General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 349 20 Tubular Catalogue
351
20.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 351 20.2 Standards . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 351 20.3 Groups . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 352 20.4 Manufacturing Process . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 352 20.5 Chemistry . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 354 20.6 Inspection and Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 354 20.6.1 Range . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 355 20.6.2 Drift Diameter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 356 20.6.2.1 Exceptions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 356 20.6.3 Hydrostatic Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 356 20.6.4 Mechanical Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 357 20.6.5 Flaw Inspection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 359 EPT Drilling
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20.7 Couplings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 360 20.8 Marking, Coating and Thread Protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 360 20.9 Pipe Inventory . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 361 20.9.1 Standard Inventory Pipe and Connections . . . . . . . . . . . . . . . . . . . . . . . . . 361 21 Derivation of the Soft String Equations
391
21.1 Coordinate Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 391 21.2 Equilibrium . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 392 21.3 Normal Force Equation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 395
IV
Revision History
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List of Figures 5.1
Sample Functional Well Specification (FWS). . . . . . . . . . . . . . . . . . . . . . . . . . . .
50
6.1
StressCheck File Menu and Commands . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
60
6.2
StressCheck Edit Menu and Commands . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
62
6.3
StressCheck Wellbore Menu and Commands . . . . . . . . . . . . . . . . . . . . . . . . . . . .
63
6.4
StressCheck Tubular Menu and Commands . . . . . . . . . . . . . . . . . . . . . . . . . . . .
64
6.5
StressCheck View Menu and Commands . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
67
6.6
StressCheck Tools Menu and Commands . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
68
6.7
StressCheck Window Menu and Commands . . . . . . . . . . . . . . . . . . . . . . . . . . . .
68
6.8
StressCheck Help Menu and Commands . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
69
6.9
Recommended StressCheck Design Ellipse . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
71
6.10 Wellcat Drill and Prod Menu Structure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
71
6.11 Wellcat Inventories Menu and Commands . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
73
6.12 Wellcat Wellbore Menu and Commands . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
80
6.13 Wellcat Loads Menu and Commands . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
83
7.1
Casing Setting Depth Diagram . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
93
7.2
Example Pore Pressure and Fracture Gradient Plot with Margins in Place . . . . . . . . . . .
98
7.3
Example Pore Problem following Initial Selection of Casing Seats . . . . . . . . . . . . . . . . 100
7.4
Example Pore Problem following Check for Differential Sticking . . . . . . . . . . . . . . . . . 102
7.5
Minimum Setting Depth for Structural Conductor Casing to Prevent Lost Circulation . . . . 105
7.6
Composite Overburden Stress Gradient . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 108
7.7
Ultimate Pile Capacity Example, Green Canyon, Gulf of Mexico . . . . . . . . . . . . . . . . 114
7.8
Conductor Tension Load vs. Time . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 115
7.9
Anticipated Mud Weights/Fracture Gradients, Keathley Canyon 255 No. 1 Example . . . . . 117
8.1
Collapsed 16 in. casing recovered from Pompano A-31 . . . . . . . . . . . . . . . . . . . . . . 123
8.2
Collapse loadings for casing installation (cementing). . . . . . . . . . . . . . . . . . . . . . . . 125
8.3
Cement Channels and Washed-Out Hole Sections . . . . . . . . . . . . . . . . . . . . . . . . . 128
8.4
Collapse Load while Drilling into LC Zone (No Top-Up Water Supply Available) . . . . . . . 129
8.5
Collapse Load due to Partial Evacuation to DSOH . . . . . . . . . . . . . . . . . . . . . . . . 129
8.6
External Hydrostatic Pressure Loads - Production Tubulars . . . . . . . . . . . . . . . . . . . 131
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8.7
Calculated Collapse Pressure Resistance for N80 Tubulars . . . . . . . . . . . . . . . . . . . . 134
8.8
Non-Uniform Loads Considered by Nester et al. [68] . . . . . . . . . . . . . . . . . . . . . . . 139
9.1
Ruptured Casing from Connection Test with internal pressure . . . . . . . . . . . . . . . . . . 144
9.2
Cement Service Life Load - Bumping Plug . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 147
9.3
internal pressure Loads for Development Well . . . . . . . . . . . . . . . . . . . . . . . . . . . 153
10.1 Tubular in a Deviated Wellbore . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 157 10.2 Buoyancy Effect on Axial Force . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 158 10.3 Buoyancy Effect on Tapered Tubular String . . . . . . . . . . . . . . . . . . . . . . . . . . . . 159 10.4 Ballooning Effects on Tension Forces . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 162 10.5 Polished Bore Receptacles and Expansion Joints . . . . . . . . . . . . . . . . . . . . . . . . . 168 11.1 Principal Stresses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 172 11.2 Triaxial Load Capacity Diagram . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 173 11.3 Locations for von Mises Stress Calculations with Bending . . . . . . . . . . . . . . . . . . . . 175 12.1 Photograph of Permanently Corkscrewed Tubing . . . . . . . . . . . . . . . . . . . . . . . . . 182 13.1 What Is Wear? . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 188 13.2 Adhesive Wear . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 188 13.3 Abrasive Wear . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 189 13.4 Grinding Wear . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 189 13.5 Constant Wear Force but Decreasing Wear Pressure . . . . . . . . . . . . . . . . . . . . . . . 190 13.6 Transition Pressure - Grinding to Machining Wear . . . . . . . . . . . . . . . . . . . . . . . . 191 13.7 Experimentally Measured Wear Factor . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 192 13.8 Example of Contact Intensity Multiplier Behavior, 13-3/8 in. 72 lb/ft casing, TJ OD 6.5 in. . 193 13.9 Estimation of Casing Wear . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 194 13.10Wear Estimation Procedure - Chart 1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 197 13.11Wear Estimation Procedure - Chart 2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 198 13.12Wear Estimation Procedure - Chart 3 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 198 13.13Wear Estimation Procedure - Chart 4 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 199 13.14Wear Estimation Procedure - Charts 5 and 6 . . . . . . . . . . . . . . . . . . . . . . . . . . . 199 13.15Wear Estimation Procedure - Charts 7 and 8 . . . . . . . . . . . . . . . . . . . . . . . . . . . 200 13.16Wear Estimation Procedure - Charts 9 and 10 . . . . . . . . . . . . . . . . . . . . . . . . . . . 200 13.17Wear Estimation Procedure - Charts 11 and 12 . . . . . . . . . . . . . . . . . . . . . . . . . . 201 13.18Effect of Groove Type Tool Joint Wear on Collapse Resistance, 9-5/8 in. 53.5 lbf/ft L-80 [77] 202 13.19Tool Joint 18◦ Taper: First Point of Contact at Crossover . . . . . . . . . . . . . . . . . . . . 203 13.20Casing Couplings and the Hump Effect . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 204 13.21Tool Joint Cross Section . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 205 14.1 Example Static Temperature Profile . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 214 14.2 Example Cementing Temperature Profile EPT Drilling
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14.3 Example Drilling and Production Temperature Profiles . . . . . . . . . . . . . . . . . . . . . . 219 14.4 HPHT Well Schematic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 220 14.5 HPHT DST Temperature Profiles . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 221 14.6 Yield Strength Temperature Derating Factors . . . . . . . . . . . . . . . . . . . . . . . . . . . 222 15.1 Jackup Design Envelope . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 229 15.2 Jackup Design Selection Procedure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 230 15.3 Sealed Annuli . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 233 15.4 Gas Migration Calculation Procedure
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 244
15.5 Design Scenarios for Post-Installation Nitrogen Behavior (Typical Thunder Horse Design) . . 247 15.6 Example Wellbore . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 248 15.7 Uncertainty in Performance Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 249 15.8 Rupture Disk for Processing Plants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 249 15.9 Rupture Disk for Tubulars . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 250 15.10Schematic to Illustrate Inward-acting Rupture Disks . . . . . . . . . . . . . . . . . . . . . . . 251 15.11Hunting O-Ring Seal Configuration for Outward-acting Rupture Disks . . . . . . . . . . . . . 255 15.12Length of 11-3/4 in. Casing With Molded Syntactic Foam Module . . . . . . . . . . . . . . . 257 15.13Composite (Casing/Foam) Length Before Running Downhole . . . . . . . . . . . . . . . . . . 257 15.14Typical Behavior of Syntactic Foam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 258 15.15Effect of Temperature on Crush Pressure of Syntactic Foam . . . . . . . . . . . . . . . . . . . 261 15.16Determination of Onset of Crushing in Syntactic Foam Modules . . . . . . . . . . . . . . . . . 263 15.17Composite Length of Casing and Syntactic Foam in Bolster . . . . . . . . . . . . . . . . . . . 265 15.18Four Lengths of Casing and Syntactic Foam in Bolster . . . . . . . . . . . . . . . . . . . . . . 265 15.19Tieback Configuration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 267 15.20Base Plate Load Distribution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 280 15.21Schematic of Valve Removable Re-injection Nozzle . . . . . . . . . . . . . . . . . . . . . . . . 285 15.22Schematic Indicating the Use of Centralizers . . . . . . . . . . . . . . . . . . . . . . . . . . . . 288 15.23TOC Schematic for Cuttings Re-injection Well . . . . . . . . . . . . . . . . . . . . . . . . . . 290 15.24Maximum Wellhead Pressure Variation with Depth and Slurry SG, Miller Example . . . . . . 294 15.25Maximum Wellhead Pressure Variation with Depth and Slurry SG, Miller Example . . . . . . 295 16.1 Working Stress Design . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 300 16.2 Overview of Probabilistic Design . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 301 16.3 Load and Performance specification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 305 16.4 Statistical Distribution of Wall Thickness, 5.500 in., 15.5 ppf, J55, Sample Size 111 . . . . . . 306 16.5 Cumulative Distribution, 5.500 in., 15.5 ppf, J55, Sample Size 111 . . . . . . . . . . . . . . . 306 16.6 Wall Thickness Distribution, 5.500 in., 15.5 ppf, J55, Sample Size 111 . . . . . . . . . . . . . 307 17.1 T&C Connection Designed on Upset - Hunting TKC . . . . . . . . . . . . . . . . . . . . . . . 311 17.2 Thread Flank Forces on API Round Thread . . . . . . . . . . . . . . . . . . . . . . . . . . . . 311 17.3 Integral Connection with Negative Load Flank Angle - Tenaris-Hydril SLX . . . . . . . . . . 312 17.4 T&C Connection with Negative Load Flank and Reverse Torque Shoulder - VAM TOP . . . 313 EPT Drilling
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17.5 Integral Connection with Negative Load and Stab Flank Angle - Tenaris-Hydril 521 . . . . . 314 17.6 T&C Connection with Metal-to-Metal Seal and Torque Shoulder - VAM TOP . . . . . . . . . 316 17.7 Integral Connection with Cylindrical Thread Profile - Benoit BTS-6 . . . . . . . . . . . . . . 318 17.8 T&C Connection with Torque Shoulder - VAM TOP . . . . . . . . . . . . . . . . . . . . . . . 319 17.9 Integral Connection Performance Ellipse - Vam SLIJ II . . . . . . . . . . . . . . . . . . . . . . 319 17.10Connection Selection Decision Tree (continued on Figure 17.11) . . . . . . . . . . . . . . . . . 329 17.11Connection Selection Decision Tree (continued from Figure 17.10) . . . . . . . . . . . . . . . 330 18.1 Materials Selection Production Casing Strings Exposed to Completion Brines/Drilling Mud . 333 18.2 Sulfide Stress Cracking Performance Domain of Grade N80 Carbon Steel . . . . . . . . . . . . 338 18.3 Sulfide Stress Cracking Performance Domain of Grade P110 Carbon Steel . . . . . . . . . . . 339 18.4 Sulfide Stress Cracking Performance Domain of C110 (Sour Resistant Grade) Low-Alloy Steel 340 18.5 Sulfide Stress Cracking Performance Domain of SM125S Low-Alloy Steel (for Casing . . . . . 341 18.6 Diagrammatical Representation of the Corrosion Process for Iron . . . . . . . . . . . . . . . . 344 21.1 Definition of Coordinate Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 392 21.2 Free Body Diagram of Element of Tube (Internal Pressure Contribution Not Shown.) . . . . . 394
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List of Tables 3.1
Wear Coefficients of Tool Joint Hard-Banding . . . . . . . . . . . . . . . . . . . . . . . . . . .
17
3.2
Casing Wear Table . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
18
3.3
Typical Values of Static Bottom Hole Temperature . . . . . . . . . . . . . . . . . . . . . . . .
19
3.4
Bullheading Temperature Recommendations . . . . . . . . . . . . . . . . . . . . . . . . . . . .
21
3.5
Long Term Injection Temperature Recommendations . . . . . . . . . . . . . . . . . . . . . . .
21
3.6
BP Minimum Casing and Tubing Design Factors . . . . . . . . . . . . . . . . . . . . . . . . .
23
3.7
Conductor Casing Design Loads . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
24
3.8
Surface, Intermediate and Drilling Casing Design Loads . . . . . . . . . . . . . . . . . . . . .
25
3.9
Production Casing and Liner Design Loads . . . . . . . . . . . . . . . . . . . . . . . . . . . .
26
4.1
Unit Usage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
45
4.2
Units and Unit Conversion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
47
6.1
Input Tips and Guidelines for the StressCheck File Menu . . . . . . . . . . . . . . . . . . . .
60
6.2
Input Tips and Guidelines for the StressCheck Edit Menu . . . . . . . . . . . . . . . . . . . .
62
6.3
Input Tips and Guidelines for the StressCheck Wellbore Menu . . . . . . . . . . . . . . . . .
63
6.4
Input Tips and Guidelines for the StressCheck Tubular Menu . . . . . . . . . . . . . . . . . .
64
6.5
Input Tips and Guidelines for the StressCheck View Menu . . . . . . . . . . . . . . . . . . . .
67
6.6
Input Tips and Guidelines for the StressCheck Tools Menu . . . . . . . . . . . . . . . . . . .
68
6.7
Input Tips and Guidelines for the StressCheck Help Menu . . . . . . . . . . . . . . . . . . . .
69
6.8
Production Load Cases for BP Template in StressCheck . . . . . . . . . . . . . . . . . . . . .
70
6.9
Drilling Load Cases for BP Template in StressCheck . . . . . . . . . . . . . . . . . . . . . . .
70
6.10 Wellcat Modular Structure
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
72
6.11 Input Tips and Guidelines for the Wellcat Inventories Menu . . . . . . . . . . . . . . . . . . .
73
6.12 Input Tips and Guidelines for the Wellcat Wellbore Menu . . . . . . . . . . . . . . . . . . . .
80
6.13 Input Tips and Guidelines for the Wellcat Loads Menu . . . . . . . . . . . . . . . . . . . . . .
84
6.14 Input Tips and Guidelines for CWear Drill Pipe Protectors . . . . . . . . . . . . . . . . . . .
87
7.1
Pore Pressure Gradients for Example Problem on Casing Seat Selection . . . . . . . . . . . .
96
7.2
Fracture Pressure Gradients for Example Problem on Casing Seat Selection . . . . . . . . . .
97
7.3
Final Casing Seats for Example Problem . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 101
7.4
Diesel Hammer Specifications (Ref. www.hammersteel.com) . . . . . . . . . . . . . . . . . . . 106
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7.5
Suggested Poisson’s Ratio for Different Lithologies (From [94]) . . . . . . . . . . . . . . . . . 107
7.6
Sizing Table for Tubulars and Bits–Traditional Units . . . . . . . . . . . . . . . . . . . . . . . 119
7.7
Sizing Table for Tubulars and Bits–SI Units . . . . . . . . . . . . . . . . . . . . . . . . . . . . 120
8.1
Collapse Mode Boundaries for D/t Ranges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 136
10.1 Example of Possible Tubing Axial Load Cases . . . . . . . . . . . . . . . . . . . . . . . . . . . 168 11.1 Triaxial Stress Example Calculation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 176 12.1 Column Buckling Criterion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 178 12.2 Effective Tension Example Calculation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 179 12.3 Buckling Example Calculation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 185 13.1 Wear Coefficients of Tool Joint Hard-Banding . . . . . . . . . . . . . . . . . . . . . . . . . . . 196 13.2 Caliper Tools . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 208 14.1 Temperature Profile Subscript Abbreviations . . . . . . . . . . . . . . . . . . . . . . . . . . . 211 14.2 Variation of Mudline Temperature with Water Depth . . . . . . . . . . . . . . . . . . . . . . . 213 14.3 Bullheading Temperature Recommendations . . . . . . . . . . . . . . . . . . . . . . . . . . . . 219 14.4 Long Term Injection Temperature Recommendations . . . . . . . . . . . . . . . . . . . . . . . 219 14.5 Recommended Yield Strength Temperature Derating . . . . . . . . . . . . . . . . . . . . . . . 222 15.1 Thermal Expansivity (10−4 / [◦ F] ) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 236 15.2 Compressibility of Muds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 237 15.3 APB Mitigation Tools . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 238 15.4 Simplified Nitrogen Gas Cap Example . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 239 15.5 Summary of OSECO Rupture Disk Test Data . . . . . . . . . . . . . . . . . . . . . . . . . . . 252 15.6 Summary of Fike Rupture Disk Test Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 253 15.7 Fike Temperature Deration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 255 15.8 Typical Record of Slurry Batch Properties and Cumulative Erosion . . . . . . . . . . . . . . . 284 15.9 Miller Casing Design . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 293 15.10Maximum Surface Pressures due to Burst at the Re-Injection Shoe . . . . . . . . . . . . . . . 293 15.11Maximum Surface Pressures due to Collapse at the Crossover Point . . . . . . . . . . . . . . 294 16.1 Design Collapse Determination for a Small Dataset . . . . . . . . . . . . . . . . . . . . . . . . 304 17.1 BP Connection Classes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 316 17.2 Large OD Connections for Casing (Non-Rotating, Weight Set)
. . . . . . . . . . . . . . . . . 324
17.3 Large OD Connections for Casing (Threaded) . . . . . . . . . . . . . . . . . . . . . . . . . . . 324 17.4 Threaded and Coupled Connections for Tubing and Casing . . . . . . . . . . . . . . . . . . . 325 17.5 Integral Connections for Casing (Expanded/Swaged or Semi-Flush Type) . . . . . . . . . . . 326 17.6 Integral Connections for Tubing and Casing (Flush) . . . . . . . . . . . . . . . . . . . . . . . 326 17.7 Integral Connections for Tubing and Casing (Upset) . . . . . . . . . . . . . . . . . . . . . . . 327 EPT Drilling
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17.8 Guidelines for Thread Selection with Wellbore Curvature . . . . . . . . . . . . . . . . . . . . 327 18.1 Acceptable API Specifications for Tubular Goods . . . . . . . . . . . . . . . . . . . . . . . . . 336 18.2 Typical Brines used as Completion Fluids . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 342 20.1 Process of Manufacture and Heat Treatment (API Specification 5CT or ISO 11960 [10]) . . . 353 20.2 Chemical Requirements (by Percentage of Weight, API Specification 5CT or ISO 11960 [10])
355
20.3 Dimensions and Tolerances (API Specification 5CT or ISO 11960 [10]) . . . . . . . . . . . . . 355 20.4 Range Lengths (API Specification 5CT or ISO 11960 [10]) . . . . . . . . . . . . . . . . . . . . 356 20.5 Alternate Drift Diameters (API Specification 5CT or ISO 11960 [10]) . . . . . . . . . . . . . . 357 20.6 Grade Mechanical Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 358 20.7 Pipe Body Inspection Methods . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 359 20.8 Acceptance (Inspection) Levels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 360 20.9 Size (Label 1) 2-3/8 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 362 20.10Size (Label 1) 2-7/8 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 362 20.11Size (Label 1) 3-1/2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 363 20.12Size (Label 1) 4 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 363 20.13Size (Label 1) 4-1/2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 364 20.14Size (Label 1) 5 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 365 20.15Size (Label 1) 5-1/2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 366 20.16Size (Label 1) 7 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 367 20.17Size (Label 1) 7-5/8 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 368 20.18Size (Label 1) 7-3/4 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 369 20.19Size (Label 1) 8-5/8 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 369 20.20Size (Label 1) 9-5/8 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 370 20.21Size (Label 1) 9-7/8 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 370 20.22Size (Label 1) 10 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 371 20.23Size (Label 1) 10-3/4 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 371 20.24Size (Label 1) 11-3/4 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 372 20.25Size (Label 1) 11-7/8 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 372 20.26Size (Label 1) 13-3/8 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 373 20.27Size (Label 1) 13-5/8 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 374 20.28Size (Label 1) 16 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 374 20.29Size (Label 1) 18 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 375 20.30Size (Label 1) 18-5/8 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 375 20.31Size (Label 1) 20 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 376 20.32Size (Label 1) 22 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 377 20.33Size (Label 1) 24 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 378 20.34Size (Label 1) 26 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 379 20.35Size (Label 1) 28 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 379 20.36Size (Label 1) 30 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 380 EPT Drilling
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20.37Size (Label 1) 36 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 381 20.38Standard Inventory Pipe Performance Properties . . . . . . . . . . . . . . . . . . . . . . . . . 382
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Part I
Overview and Policies
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Chapter 1
Overview 1.1
Objective
The objective of the BP Tubular Design Manual is to establish a consistent design methodology throughout BP, and identify the loadings which should, as a minimum be considered in a tubular design. While this manual identifies recommended practice, government regulations or local considerations may require that designs be carried out to a standard exceeding that in this manual. This part (A) of the manual identifies the overall policies which tubular design procedures are intended to satisfy. Part B provides an aide memoire for those who are fully familiar with tubular design and require only to be reminded of load cases and design factors. Part C provides detailed guidance on design requirements and calculation methods. This manual has drawn on contributions from engineers in various Business Units and EPT. Users of the manual are invited to suggest improvements and identify errors following the procedure in Part C, Section 4.2.
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Chapter 2
Policy The BP Drilling and Well Operations Policy (BPA-D-001) has been replaced by a library of Engineering Technical Practices (ETPs), the particular practice applicable to casing and tubing design being GP 10-01, Casing and Tubing Design Group Practice [17], and its summary in the BP Drilling and Well Operations Practice. This entire document is applicable to tubular design, but contains within the statement that, The requirements contained within the BP Tubular Design Manual (BPA-D-003) shall be applied for both the tubing and casing program basis of design. The basis of design will address parameters within which it is acceptable to plan further wells in a programme, campaign or area without further detailed design. When these parameters are exceeded, a detailed reassessment of the design is required. This represents a departure from previous practice where the BP Tubular Design Manual was regarded as a recommended, but not necessary, source for tubular design. For this reason, care is required to ensure the components of the current manual are honored. The latest version of GP 10-01, Casing and Tubing Design Group Practice can be found on the BP intranet at the Group ETP library1 in Category 10.
2.1
Deviations from Policy
The advent of Engineering Authorities (EAs) in SPUs and Segment Engineering Technical Authorities (SETAs) at the segment level has resulted in a revision of the deviation policy. The BP Drilling and Well Operations Practice (BPA-D-001) outlines the procedure for seeking approval for deviations from group practices.
2.1.1
SPU Deviations
Site Technical Practices (STPs) are permanent deviations from the Segment ETPs, and are owned by SPU Engineering Authorities (EAs) and Technical Authorities (TAs). SPUs who have no approved deviations from the Segment ETP govern their casing and tubing design according to the Segment ETP. Note that: 1 http://etplib.bpweb.bp.com/sitePreferences.jsp
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• It is not necessary that an SPU create an STP for each ETP; • An STP is the same as its corresponding ETP with approved local deviations included, not an entirely new document; • The primary use of STPs is to record permanent local deviations from the corresponding ETP. Deviations from DWOP that are not associated with an ETP are endorsed by the SPU TA and approved by the SPU EA.
2.1.2
Segment Deviations
The Segment ETPs are owned by the SETAs. Application specific, as opposed to permanent deviations from ETPs. Although deviations to an ETP are endorsed by the appropriate SETA, the SPU EA still has approval authority for the deviation.
2.1.3
Deviation Management
A (solitary) deviation, once approved, is stored in the well file. A STP is uploaded to the Group ETP library.
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Part II
Quick Guide
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Chapter 3
Quick Guide This “Quick Guide” is intended to provide a compact reference to tubular design for those who do not require the explanations and background material in Part III. The layout follows that of the detailed manual. Table 3.6 presents an overview of design factors. This guide is not a replacement for the detailed manual of Part III, and not all its provisions and guidance are included here. It is assumed that tubular design will usually be performed using a recommended software package that has been validated within BP (see Chapter 6.
3.1
Data Needed Before Design
• Well location, total depth, water depth and objective depth(s). • Deviation of the wellbore. • Designation as exploration or development well–the probability of completing as a development well significantly impacts both casing design and material selection. Serious discussions should precede any well being designated exploration-only. The expense and risk associated with converting an explorationonly well to a development well may be prohibitive. • Timing requirement, which impacts rig availability and long lead items. • Evaluation requirements (logging, coring, or testing), which impact hole size and mud types. • Testing or production rates required, which impacts the sizing of tubing and production casing. As the tubing size is selected to optimize well productivity, all outer strings, beginning with the production casing, are sized depending on the tubing diameter. • Hydrocarbon composition–gas or oil? Corrosion anticipated from H2 S/CO2 /Cl impacts material selection, cost and lead time for tubulars. • Producing life of well and completion design’s intervention procedures. Particular attention should be paid to completion aspects of the well life, such as clearance for possible artificial lift, the potential EPT Drilling
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for multiple/dual completions, provision for washing over tubing and the potential for exploration deepening. • Geological information (formation tops, faults, structure maps, etc.). • Pore pressure and fracture gradient profiles. • Offset well data (casing and tubing programs, geological tie-in, operational problems, drilling fluid densities, etc.). • Hazards and constraints (shallow gas, lease line restrictions, faults, rig if selected, BOP size, equipment import restrictions, casing stocks, etc.). • Undisturbed temperature profile. • Anticipated production/injection rates and fluid composition(s). • Downhole completion component sizes. • Annulus communication, bleed off and monitoring policies (particularly applicable to development wells).
3.2
Design Summary
While initial design often proceeds from the bottom up (i.e., starting from the required completion size) final design calculations are best presented in the order of operations. This assists in identifying all the loads to which the casing may be exposed.
3.2.1
Installation Loads
3.2.1.1
Casing
For casing, installation loads include: • Running casing; – Conventional cementing or – Stab in cementing or – Stinger cementing without stab in; – Bumping cement plug; • Cementing operations. For tubing, installation loads include: • Running tubing; • Packer setting operations. EPT Drilling
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For casing the forces and displacements present when the cement sets establish the initial conditions of the string. All subsequent load cases superimpose changes on the initial condition. The initial condition is determined by: • Buoyed weight, calculated considering the fluid pressures acting on all shoulders, not via a buoyancy factor; • Internal hydrostatic pressure associated with the displacing fluid, usually a drilling fluid, water or brine; • External hydrostatic pressure as determined by the column of drilling fluid, spacer and cement; • The cementing temperature following WOC; • Any surface pressure held during WOC1 .
3.2.1.2
Tubing
For tubing, installation loads include: • Running tubing; • Packer setting operations. For tubing the packer serves the function of the casing cement for defining the initial conditions for the string. All subsequent load cases superimpose changes on the initial condition. The initial condition is determined by: • Buoyed weight, calculated considering the fluid pressures acting on all shoulders, not via a buoyancy factor; • Internal and external hydrostatic pressures associated with the completion fluid2 ; • The undisturbed temperature unless simulation indicates a more accurate temperature profile is crucial to proper design calculations; • Any surface pressure held against a plug in order to set the packer. 1 It may be necessary to apply pressure should the float fail during cementing. Otherwise, only in the rarest circumstances will it be necessary to hold pressure during the cement thickening time. An undesirable consequence of holding internal pressure during WOC is the creation of a microannulus when the cement has solidified and the pressure is released. 2 Usually
tubing will be installed with the same fluid inside and out. However, in some instances circulation of fluids prior to setting the packer will result in different fluid conditions internal and external to the tubing. In such cases, proper accounting should be made for the fluid environment at the time that the packer fixes the tubing.
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3.2.2
Drilling Load Cases (Casing)
• Pressure testing of casing after WOC; • Maximum drilling fluid density and temperature rise for next section; • Well control, gas influx loads; • Lost circulation; • Cuttings injection in annuli;
3.2.3
Production Load Cases (Casing)
• Pressure testing with completion fluid or mud as required; • DST pressure testing with mud or kill weight fluids; • DST–Gas or hydrocarbons to surface; • Near surface tubing leak during production; • Collapse loading due to completion fluids or operations; • Collapse loading below production packers; • Special production operations, i.e., injection, gas lift, stimulations, ESPs;
3.2.4
Production Load Cases (Tubing)
• Pressure testing, internal and external; • Shut-in, both short (hot) and long (cold) term; • Production3 ; • Cold kill down tubing; • Additional production operations4. 3 A significant load contributor during production is temperature change. The hottest temperature profile a wellbore experiences may not be early in the well life, but rather coincident with the onset of water production 4 Tubing
designs are notorious for generating a large number of load cases, depending on both production and remediation operations conducted during the life of the string. Careful thought should be given to the variety of scenarios the tubing might experience during its service.
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3.2.5
Casing Setting Depths
Factors affecting casing setting depth selection: • Well control; • Shallow gas zones; • Lost circulation zones; • Formation stability which is sensitive to exposure time or drilling fluid density; • Directional well profile; • Sidetracking requirements as specified in the FWS; • Fresh water sands; • Hole cleaning; • Salt sections; • High pressure zones; • Isolation of H2 S and CO2 bearing intervals; • Casing shoes shall, where practicable, be set in competent formations; • Uncertainty in depth estimating; • Well depth; • The presence of multiple producing intervals; • The possibility of differential sticking; • Surge pressures when running casing.
3.2.6
Collapse Design
The provisions below are applicable to casing conforming to API specifications. For D/t greater than the ratio for elastic collapse (e.g., (D/t)te ), the requirement is 2t API/ISO Collapse Rating pc = po − 1 − pi ≤ fwear × , D DFc
(3.1)
For D/t ratios resulting in elastic collapse, (1 − 2t/D) pi is replaced by pi . Collapse is discussed in Chapter 8, with the API/ISO collapse rating calculated in Section 8.4.2.1. Wear is discussed in Chapter 13. EPT Drilling
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3.2.7
Burst Design
The provisions below are applicable to casing conforming to API specifications. pi − po ≤ fwear × fT ×
API/ISO Internal Yield Pressure Rating , DFb
(3.2)
Design for burst during running is required only if the pressure test occurs before cementing (refer to Drilling and Well Operations Practice, Section 21, and to Tables B.1 to B.4.). Burst is discussed in Chapter 9. Wear is discussed in Chapter 13. Temperature degradation of yield strength is discussed in Chapter 14, with recommended temperature deration factors tabulated in Table 14.5.
3.2.8
Tension Design
Design requirements, Fa ≤ fwear ×
Lesser of Pipe Body and Connection Rating , DFt
(3.3)
where DFt is 1.4 for casing, 1.33 for tubing (in service). Use TVD for gravity loads. Tension design is discussed in Chapter 10. 3.2.8.1
Running (Casing or Tubing)
Shock loading, Fa = Fwt + Fbuoy + Fb + Fshock ,
(3.4)
Fa = Fwt + Fbuoy + Fb + Fop ,
(3.5)
Overpull,
If Fa for overpull is less than 100 kips a detailed study is recommended. 3.2.8.2
Cementing (Casing)
Fa = Fwt + Fbuoy + Fb + Fplug ,
(3.6)
where Fwt is calculated for both cement and displacement fluid as the internal fluid. 3.2.8.3
Initial Condition (Casing or Tubing)
The same equation is used for both casing and tubing, but the interpretation of the force components differs (see Section 10.4). Fai = Fwt + Fbuoy + Fb + Fplug + Fl . EPT Drilling
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3.2.8.4
Drilling and Production (Casing or Tubing)
Fa = Fai + Fbal + FT + Ff r + ∆Fpkr ,
(3.8)
where ∆Fpkr applies only to tubing. Bullheading cold well kill fluid may be worst tension case if buckling has been prevented by the landing procedure.
3.2.9
Triaxial Design
Triaxial design is always required to ensure there are no excessive displacement or localized strain concentrations which might invalidate the burst check or cause failure on load reversal. The design requirement is, DFv =
fymn ≥ 1.25, σe
(3.9)
where σe = [σr2 + σh2 + (σa + σb )2 − σr σh − σh (σa + σb ) − (σa + σb )σr ]1/2 ,
(3.10)
with σa =
Fa , Ap
σb = σhb + σdev .
(3.11)
(3.12)
In the general case with bending present, the stresses must be calculated at both the inside and outside diameter of the tube. At the inside diameter, σri = −pi ,
σhi =
pi (D2 + d2wall ) − 2po D2 . D2 − d2wall
(3.13)
(3.14)
and for the outside diameter stress check (r = D/2) σro = −po ,
σho =
2pi d2wall − po (D2 + d2wall ) . D2 − d2wall
(3.15)
(3.16)
In the absence of bending, the peak VME stress always occurs at the pipe inside diameter. One calculation is needed if there is no bending; four calculations are needed (using maximum and minimum axial stress at both outside diameter and inside diameter) if bending is present. Triaxial design is discussed in Chapter 11. EPT Drilling
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3.2.10
Buckling and Compression
Buckling is possible if axial force decreases, temperature increases, internal pressure increases or external pressure decreases from the as cemented or as landed state. Buckling and compression are discussed in Chapter 12. Some useful formulae for buckling include: 3.2.10.1
Effective Force
Fe = Fa − (pi Ai − po Ao ). 3.2.10.2
Critical Effective Force for Sinusoidal Buckling
Fcr = − where N= and
r
(Fe sinα
r
4EIN , rc
dβ 2 dα ) + (we sinα − Fe )2 , ds ds
we = wa + (γi Ai − γo Ao ). 3.2.10.3
(3.17)
(3.18)
(3.19)
(3.20)
Post-Buckled Geometry
1. The pitch is the distance between spirals on the helix,
P =π
r
8EI . Fe
(3.21)
2. The radius of curvature of the helix is Rc =
P 2 + 4π 2 rc2 . 4π 2 rc
(3.22)
If the radius of curvature calculated in Equation 3.22 is expressed in inches, the equivalent curvature or dogleg severity (DLS) in degrees per 100 ft is c=
5730 . Rc /12
(3.23)
3. The axial stresses due to bending as the tube assumes a helical shape are calculated from Equation 3.24. σhb = ±Erc,
(3.24)
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Table 3.1. Wear Coefficients of Tool Joint Hard-Banding Tool Joint
WBM
OBM
Smooth TC
10
5
Plain Steel
6
3
Wear Resistant Alloy Overlaysa
2
2
a
Armacor M, Arnco 200 XT, etc.
3.2.10.4
Mitigating Buckling
Buckling can be eliminated or its effects reduced by: • Adjusting top of cement (usually but not always upwards); • Applying Fl after WOC; • Holding Fplug while WOC, but consult cement specialist about micro annulus risk. Design to avoid drilling through buckled uncemented casing.
3.2.11
Casing Wear
This section provides factors to accommodate casing wear. Detailed guidance can be obtained from the full manual if a satisfactory design cannot be obtained using the provisions below. The possibility of unplanned footage or additional rotating hours should be considered in arriving at an allowance for wear. Predicted wear should be compared with the allowable wear to keep within required design factors. Casing wear is discussed in Chapter 13. 3.2.11.1
Design Rules
For the purposes of a simple design check proceed as follows: • Determine the wear coefficient from mud type and hard-banding using Table 3.1. • Determine the normal force or side load either by using the Torque Drag module of WellPlan (output in lbs/100 ft) or from the following expression: N [lb/ft] = c [◦ /100 ft] × Fa [lbf ] /6, 000,
(3.25a)
N [lb/ft] = c [◦ /30 m] × Fa [lbf ] /6, 000,
(3.25b)
or in Hybrid units,
or in SI units, EPT Drilling
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Table 3.2. Casing Wear Table Casing Diameter and Weight per Foot Wear No.
13-3/8 in.
10-3/4 in.
9-5/8 in.
7 in.
68.0
61.0
54.5
55.5
51.0
45.5
53.5
47.0
43.5
40.0
32.0
29.0
26.0
23.0
0.125
17
14
12
10
10
10
10
10
10
10
10
10
10
10
0.250
25
22
18
22
18
16
20
18
16
15
22
18
16
14
0.375
32
28
25
28
25
22
28
25
23
21
30
25
22
19
N [N/m] = c [◦ /30 m] × Fa [N] /1, 350.
(3.25c)
• Determine the Wear Number,
Wear Number = 1.128 × 10−6 × Wear Coefficient × N [lb/ft] × Equivalent Rotating Hours, (3.26a) or in Hybrid units,
Wear Number = 1.128 × 10−6 × Wear Coefficient × N [lb/ft] × Equivalent Rotating Hours, (3.26b) or in SI units,
Wear Number = 7.777 × 10−6 × Wear Coefficient × N [N/m] × Equivalent Rotating Hours, (3.26c) where the Equivalent Rotating Hours are the total rotating hours times RP M/60. Determine the percentage wear from Table 3.2.
3.2.12
Temperature
Temperature is discussed in Chapter 14. Use a temperature prediction program (e.g., the Drill and Prod modules of Wellcat) if the bottom hole static temperature5 > 250◦ F, where, for onshore wells, TS [◦ F] = TSurf [◦ F] + γT [◦ F/100 ft] z [ft TVD] /100,
(3.27a)
5 The
limit of 250◦ F is approximate, and should be governed by circumstances. For example, in deep water applications a lower temperature should activate serious temperature modeling because of the importance of annular pressure build-up calculations in determining well integrity.
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Table 3.3. Typical Values of Static Bottom Hole Temperature Water Depth (ft)
Gulf of Mexico
North Sea
TSurf
80◦ F
60◦ F
500
50◦ F
45◦ F
1500
45◦ F
40◦ F
3000
40◦ F
40◦ F
γT
1.0-1.2◦F/100 ft
1.2-1.5◦F/100 ft
or in Hybrid units, TS [◦ C] = TSurf [◦ C] + γT [◦ C/30 m] z [m TVD] /30,
(3.27b)
TS [◦ C] = TSurf [◦ C] + γT [◦ C/30 m] z [m TVD] /30.
(3.27c)
TS [◦ F] = Tml [◦ F] + γT [◦ F/100 ft] (z − zw ) [ft TVD] /100,
(3.28a)
TS [◦ C] = Tml [◦ C] + γT [◦ C/30 m] (z − zw ) [m TVD] /30,
(3.28b)
TS [◦ C] = Tml [◦ C] + γT [◦ C/30 m] (z − zw ) [m TVD] /30,
(3.28c)
or in SI units,
and for offshore wells,
or in Hybrid units,
or in SI units,
Typical values of Tml and γT are given in Table 3.3. 3.2.12.1
Drilling
Bottom Hole Circulating Temperature
TBHC [◦ F] = (1.342 − 0.2228γT [◦ F/100 ft] )TBHS [◦ F] + 33.54γT [◦ F/100 ft] − 102.1,
(3.29a)
or in Hybrid units,
TBHC [◦ C] = (1.342 − 0.4075γT [◦ C/30 m] )TBHS [◦ C] + 26.83γT [◦ C/30 m] − 50.64,
(3.29b)
or in SI units, EPT Drilling
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TBHC [◦ C] = (1.342 − 0.4075γT [◦ C/30 m] )TBHS [◦ C] + 26.83γT [◦ C/30 m] − 50.64,
(3.29c)
Bottom Hole As Cemented Temperature TBHCmt = TBHC + (TBHS − TBHC )/4,
(3.30)
Surface As Cemented Temperature TSurf Cmt = TSurf + 0.3(TBHCmt − TSurf ).
(3.31)
Circulating Temperature at Surface TC3 [◦ F]
at surface = TC2 [◦ F] −
2 γT [◦ F/100 ft] zDSOH [ft TVD] (0.8) , 3 100
(3.32a)
or in Hybrid units, TC3 [ C] ◦
at surface = TC2
2 γT [◦ C/30 m] [ C] − zDSOH [m TVD] (0.8) , 3 30
at surface = TC2
2 γT [◦ C/30 m] [ C] − zDSOH [m TVD] (0.8) , 3 30
◦
(3.32b)
(3.32c)
or in SI units, TC3 [ C] ◦
TC2
◦
at 2/3 DSOH = 0.9TBHS ,
(3.33)
at DSOH = 0.95TBHS .
(3.34)
TC1 3.2.12.2
Production
For casing designs, 2 TSurf P [◦ F] = 0.95TBHS [◦ F] − zf [m TVD] 3
γT [◦ F/100 ft] 0.7 , 100
(3.35a)
TSurf P [ C] = 0.95TBHS
2 [ C] − zf [ft TVD] 3
γT [◦ C/30 m] 0.7 , 30
(3.35b)
TSurf P [ C] = 0.95TBHS
2 [ C] − zf [ft TVD] 3
γT [◦ C/30 m] 0.7 , 30
(3.35c)
or in Hybrid units, ◦
◦
or in SI units, ◦
TP EPT Drilling
◦
at 2/3 TD = 0.95TBHS , 20
(3.36) BP Confidential
Table 3.4. Bullheading Temperature Recommendations Depth
Temperature
0
Surface temperature of fluid
2/3 production zone
2/3 TBHS @ depth
Production zone
2/3 TBHS @ depth
Table 3.5. Long Term Injection Temperature Recommendations Depth
Temperature
0
Surface temperature of fluid
Injection zone
Surface temperature of fluid
TP
at producing zone = TBHS .
(3.37)
For tubing designs, TP is calculated using the same equations. However, TSurf P is modified as follows, 2 γT [◦ F/100 ft] TSurf P [◦ F] = 0.95TBHS [◦ F] − zf [ft TVD] (0.5 , 3 100
(3.38a)
2 γT [◦ C/30 m] TSurf P [◦ C] = 0.95TBHS [◦ C] − zf [m TVD] (0.5 . 3 30
(3.38b)
γT [◦ C/30 m] 2 TSurf P [◦ C] = 0.95TBHS [◦ C] − zf [m TVD] (0.5 . 3 30
(3.38c)
or in Hybrid units,
or in SI units,
3.2.12.3
Bullhead Kill
Temperatures for bullhead kills are summarized in Table 3.4. 3.2.12.4
Long Term Water Injection
Temperatures for long term water injection are summarized in Table 3.5.
3.2.13
Special Design Cases
The only general quick guidance is that a key requirement of a successful design is that all the plausible loadings during installation, operation and retrieval or abandonment have been identified. Special design cases are discussed in Chapter 15. EPT Drilling
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3.2.14
Reliability
Current developments in structural reliability applied to tubulars can offer the possibility of engineering collapse and burst pipe body ratings different from those in API TR 5C3 or ISO TR 10400 [9], having a sounder basis in both theory and data. For marginal designs particularly involving heavy wall tubulars it can be worth seeking specialist advice. Probabilistic design is discussed in Chapter 16.
3.2.15
Connection Selection
See the detailed manual, Chapter 17. Connection recommendation depends on pressure, bending and other factors. A detailed flowchart to guide selection is contained in the detailed manual.
3.2.16
Material Selection
Consult the detailed manual, Chapter 18 and EPT materials specialist if any CO2 or H2 S is expected.
3.2.17
Minimum Design Factors
Table 3.6 summarizes the minimum recommended design factors for BP casing and tubing designs.
3.2.18
Table Entries
In the Design Load Tables B.2 to B.4, the headings are: • Service Life Load–Operational load applied to the casing; • Design Factors: – T = tension design factor; – B = burst design factor; – C = collapse design factor; – V = triaxial design factor; • Additional Load Consideration–Additional analysis specific to the casing and load condition which must be considered; • DLS: dogleg severity; • internal pressure–hydrostatic Pressure Profile inside; • external pressure–hydrostatic pressure profile in the annulus; • Temperature Profile – S = Static Gradient; – CMT = Cemented temperature; EPT Drilling
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Table 3.6. BP Minimum Casing and Tubing Design Factors Casing
Tubing (Test)
Tubing Service)
Mode
Pipe
Coupling
Pipe
Coupling
Pipe
Coupling
Tension
1.4
1.4
1.1
1.1
1.33
1.33
Burst
1.1
1.1
1.1
1.1
1.25
1.25
Collapse
1.0
N/A
1.1
N/A
1.1
N/A
Triaxial
1.25
N/A
1.1
N/A
1.25
N/A
Compression
1.4
1.0
1.1
1.0
1.33
1.0
• Casing wear to be considered based on specific well program. • Triaxial analysis is required for all designs. • Design factors are applicable to seamless pipe with specified material yield of 125 ksi or lower. • A collapse design factor of 1.1 is recommended for casing with 10 < D/t < 12. • A burst design factor of 1.0 is recommended for surface, intermediate and drilling casing well control • It is expected that any dispensations will in general be based on a critical • Tension design factor is applied to yield of both pipe body and connection critical cross section. • Refer to GP 10-01, Casing and Tubing Design Group Practice [17] for mandatory loads.
– CT = Circulating temperature drilling; – PT = Production temperature;
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Table 3.7. Conductor Casing Design Loads Load Case
Conductor Installation
Service Life Load
Design
Condition
Factors
Running conductor
T – 1.4
Additional Load Considerations
internal pressure
external pressure
Temp. Profile
SW/MW run in
SW/MW run in
• Bending due to DLSa • Possible axial load due to lost S
circulation during running
Cementing
Burst loads after
job–
T – 1.4
• Bending due to DLSa • Axial load from bumping plug
MW or displacing fluid
T – 1.4 C – 1.0
• Bending due to DLSa
MW
MW, spacer, cement column from TOC + bridging during operationb
T – 1.4 B – 1.1
• Bending due to DLSa • Additional axial loads created by pressure test as calculated based
Pressure + fluid density during test
Pore pressure/SW gradient
For
MW used to set casing
conventional
B – 1.1 C – 1.0
Cement job–stab in
Drilling–pressure (if applicable)
test
installation
MW, spacer, cement column from TOC
on Poisson’s effect (ballooning)
Collapse loads
Drilling–lost circulation
after installation
T – 1.4 C – 1.0
• Tension analysis • Bending due to DLSa
offshore/onshore
wells
with sufficient source of water, the lowest internal gradient will be SW or FW, or evacuation or partial evacuation of casing due to mud column falling when drilling into an LC zone; mud column to fall until the hydrostatic pressure balances the LC zone, or complete evacuation if air or foam drilling.
MW–drilling fluid density, SW–sea water a See Chapters 10 and 12. b Caution, packing of the annulus can result in high collapse loads.
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Table 3.8. Surface, Intermediate and Drilling Casing Design Loads Load Case
Service Life Load Condition
Design Factors
Additional Load Considerations
internal pressure
external pressure
Temp. Profile
During Installation
Running casing
T – 1.4
• Bending due to DLSa • Possible axial load due to lost circulation during running
MW run in
MW run in
S
Cementing– conventional as cemented Base Case
T – 1.4 B – 1.1 C – 1.0
• Bending due to DLSa
Displacing fluid
MW/SW (as applicable), spacer, cement column from TOC
CMT
Cementing–stab in job
T – 1.4 C – 1.0
• Bending due to DLSa
MW
MW, spacer, cement column from TOC + bridging during operationb
Bumping cement plugs
T – 1.4 B – 1.1 V – 1.25
• Bending due to DLSa • Axial load due to pressure acting across area of casing ID
Displacing fluid + pressure used to bump plug
MW, spacer, cement column from TOC
Drilling–pressure test
T – 1.4 B – 1.1 V – 1.25
• Bending due to DLSa
Pressure + fluid density during test
Mix fluid above TOC; mix fluid below TOC to previous shoe if TOC above shoe, pore
Burst loads after installation
• Additional axial loads created by pressure test as calculated based on Poisson’s effect (ballooning)
pressure in open hole assuming cement provides axial pressure isolation
• Casing wear, as required
Drilling–max
drilling
MW if not cemented to surface
T – 1.4 B – 1.1 V – 1.25
• Bending due to DLSa • Additional axial loads created by pressure increment based on Pois-
Maximum MW to drill DSOH
T – 1.4 B – 1.1
expected on basis of much data
V – 1.25
• Bending due to DLSa • Additional axial loads created by pressure increment based on Poisson’s effect (ballooning)
Collapse loads after
T – 1.4
hydrocarbon
B – 1.0 V – 1.25
Drilling–lost circulation
installation
T – 1.4 C – 1.0 V – 1.25
• Bending due to DLSa • Additional axial loads created by
Seawater gradient from shoe fracture pressure
Mix fluid above TOC; mix fluid below TOC to previous shoe if TOC above shoe, pore pressure in open hole assuming cement provides axial pressure isolation
Gas gradient from shoe frac-
Mix fluid above TOC; mix
ture pressure
fluid below TOC to previous shoe if TOC above shoe, pore pressure in open hole assuming cement provides axial
pressure increment based on Poisson’s effect (ballooning) • Casing wear, as required • Helical buckling
• Tension Analysis • Biaxial effect on collapse resistance due to axial stress
CT
pressure isolation
• Casing wear as required
Well control, possible
Mix fluid above TOC; mix fluid below TOC to previous shoe if TOC above shoe, pore pressure in open hole assuming cement provides axial
son’s effect (ballooning) • Casing wear, as required • Helical buckling
Drilling–well control, no hydrocarbon
S
pressure isolation
For offshore/onshore wells with sufficient source of
MW used to set casing
S
water, the lowest internal gradient will be SW or FW, or evacuation or partial evacuation of casing due to mud column falling when drilling into an LC zone; mud column to fall until the hydrostatic pressure balances the LC zone, or complete evacuation if air or foam drilling.
MW–drilling fluid density, SW–sea water a See Chapters 10 and 12. b Caution, packing of the annulus can result in high collapse loads.
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Table 3.9. Production Casing and Liner Design Loads Load Case
Service Life Load Condition
Design Factors
Additional Load Considerations
internal pressure
external pressure
Temp. Profile
During Installation
Running casing
T – 1.4
• Bending due to DLSa • Possible axial load due to lost circulation during running
MW run in
MW run in
S
Cementing
T – 1.4 C – 1.0
• Bending due to DLSa
Displacing fluid
MW, spacer, cement column from TOC
C
T – 1.4
• Bending due to DLSa • Axial load due to pressure acting across area of casing ID
Displacing fluid + pressure
MW, spacer, cement column
used to bump plug
from TOC
• Bending due to DLSa • Additional axial loads created by Poisson’s effect (ballooning)
Pressure + fluid density during test
Mix fluid above TOC; mix fluid below TOC to previous
Bumping cement plugs
B – 1.1 V – 1.25
Exploration and Development
Pressure test
T – 1.4 B – 1.1 V – 1.25
S
shoe if TOC above shoe, pore pressure in open hole assuming cement provides axial
• Helical buckling
pressure isolation Development Burst
Miscellaneous completion operations
Loads after Installation
T – 1.4 B – 1.1 V – 1.25
• Same as pressure test casing above • Pressure and temperature loads for acid stimulation, water injection, etc. • Helical buckling
Tubing leak (also applicable to intermediate casing if used as pro-
T – 1.4 B – 1.1 V – 1.25
• Same as pressure test casing
DST pressure load
T – 1.4 B – 1.1 V – 1.25
• Same as pressure test casing
Mix fluid above TOC; mix fluid below TOC to previous
S&P
shoe if TOC above shoe, pore pressure in open hole assuming cement provides axial pressure isolation
fracture,
duction)
Exploration Burst Loads after Installation
Pressure for production loads and fluid density
Tubing surface pressure (based on dry methane unless otherwise justified) +
Mix fluid above TOC; mix fluid below TOC to previous shoe if TOC above shoe, pore
completion fluid
pressure in open hole assuming cement provides axial pressure isolation
Surface pressure for downhole tool/gun operation and MW
Mix fluid above TOC; mix fluid below TOC to previous shoe if TOC above shoe, pore pressure in open hole assuming cement provides axial pressure isolation
Gas or hydrocarbon to
T – 1.4
surface, leak
B – 1.1 V – 1.25
DST
string
• Same as pressure test casing
Gas or hydrocarbon to surface
Mix fluid above TOC; mix
from expected target pressure; for DST string leak, tubing surface pressure + MW
fluid below TOC to previous shoe if TOC above shoe, pore pressure in open hole assum-
S
ing cement provides axial pressure isolation Collapse Loads
Production collapse
after Installation
T – 1.4 C – 1.0 V – 1.25
• Tension analysis • Biaxial effect on collapse resistance due to axial stress
Annulus above packer:
During 1st year MW used to
• Lowest completion fluid to balance depleted reservoir • For gas lift operations
set casing. After 1st year pore pressure in cemented section and MW above cement.
casing will be completely evacuated to max depth • Other completions and operations Annulus below packer: • Gas gradient (.1 psi/ft) or full evacuation for gas wells • Gas lift operation • Other operations
MW–drilling fluid density, SW–sea water a See Chapters 10 and 12. b Caution, packing of the annulus can result in high collapse loads. Notes: • In cases where a significant section is to be drilled below the production casing well control considerations should be designed for. • In cases where a significant number of rotating hours are anticipated in drilling below the production casing shoe, the effects of casing wear should be considered.
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Part III
Detailed Manual
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Chapter 4
Introduction 4.1
Purpose
The objective of the BP Tubular Design Manual is to establish a consistent design methodology throughout BP, and identify the loadings which should, as a minimum, be considered in a casing or tubing design. Design factors recommended in this manual are based on both historic experience and a reliability assessment of probability of casing failure and the associated economic consequences. While this manual identifies minimum requirements it must be recognized that government regulations and/or local considerations may require that casing designs be carried out to standards exceeding those in this manual.
4.2
Procedure for Revision or Addition
Requests for revision or addition to this manual should be directed to the Tubular Technology Team EPT and must include a brief supporting argument for the proposed revision or addition. The Tubular Technology Team EPT will progress the proposed amendment and prepare appropriate revisions to the text of this manual. Significant revisions will then be reviewed for approval by the appropriate Drilling Managers. Upon approval, revisions or additions will be issued as an update to this Manual.
4.3
How to use this Manual
Definitions of terms and symbols in use throughout this manual are provided in the next Section, 4.4. The basic information needed to prepare a casing or tubing design is identified in Chapter 5. Computer software to help implement the provisions of this manual is described in Chapter 6. The first step is choosing setting depths. This is discussed in Chapter 7. Detailed technical requirements and guidance on performing the calculations identified in the flow charts are given in Chapters 8 to 19. Chapter 20 provides a comprehensive tabulation of casing mechanical properties. EPT Drilling
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4.4
Definitions and Symbols
4.4.1
Well Categories
There are two well categories with differing design requirements - exploration and development. The appropriate category depends upon how well the loads can be defined. exploration wells exploration wells have minimal offset operational pore pressure and geological data control. Service life loads are uncertain. Appraisal wells are included in this category. development wells development wells have well defined service life loads, geological control, and pore pressure regimes. Areas such as platform or field drilling–Prudhoe Bay, Ewing Banks, Miller, Wytch Farm, Atlantis, etc.–are considered development drilling areas. If a development well is to be drilled into an unexplored area of the field, then exploration well load cases shall be used for the casing that will be exposed to that exploration section of the well. An exploration well drilled from a production platform or within an existing field may also be defined as a combination of these two categories. The first casing strings in the well known formation(s) may be regarded as being a development well, whereas the deeper strings shall be treated as exploration.
4.4.2
Glossary
The following terms appear throughout this manual: AFE annular fluid expansion AISI steel grade The AISI system of classifying grades of carbon and low-alloy steel uses a four digit number to denote the steel composition. Examples likely to be encountered in the oil production industry are: 10XX series These are plain carbon steels with a maximum Manganese content of 1.0%. The XX refers to the nominal carbon content. For example, 1020 would have a nominal carbon content of 0.2%. 41XX series These are low-alloy steels containing chromium and molybdenum. The XX refers to the nominal carbon content. For example, 4137H has a nominal composition of 0.95%Cr, 0.20%Mo and 0.37%C. The “H” denotes a special hardenability requirement. 43XX series These are Ni/Cr/Mo containing low-alloy steels. The XX denotes the nominal carbon content. For example, 4340 has a nominal composition of 1.82%Ni, 0.80%Cr, 0.25%Mo and 0.40%C. annealing A heat treatment process which involves heating a steel to a predefined level, holding it at this temperature for a specified time, then slow cooling (usually by simply turning the furnace off, known as a furnace cool). The purpose of annealing is primarily to remove any cold work/residual stress within the steel. In addition, there is normally some grain refinement (reduction in grain size). Annealing results in an increase in the ductility of the steel. EPT Drilling
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APB annular pressure build-up API material grade The API standard for casing and tubing (API Specification 5CT) contains materials classification grades. These consist of a letter followed by a two or three digit number, e.g., Grade P110. The number designates the specified minimum yield strength (YS) in ksi (thousands of pounds per square inch). ASV annulus safety valve austenite High-temperature phase of iron which has a face-centered cubic crystallographic structure. In steels, the solute is generally carbon. Austenite is not generally stable at room temperature, in plain carbon steels, it is not stable below 723◦C. However, it can be stabilized by alloying, e.g., austenitic stainless steel, in which nickel is the stabilizing alloying element. austenitic stainless steel A stainless steel in which austenite is the stable phase at room temperature, normally containing chromium in the range 16 to 26% and nickel in the range 6 to 20%. These alloys can contain some ferrite (up to 5%), which can adversely affect their corrosion resistance and weldability. These steels cannot be hardened by quenching, but can only be strengthened by cold work. carbon steel Steel that owes its properties chiefly to the carbon content of the material rather than the presence of other alloying elements which are seldom present in appreciable amounts. Charpy test An impact test in which a notched bar sample, fixed at both ends, is struck by a falling pendulum. The energy absorbed, as determined by the subsequent rise of the pendulum, is a measure of the impact strength or notch toughness. This value is known as the Charpy Impact value and is normally quoted in either Joules or foot-pounds. The test temperature and specimen orientation are also important parameters and these are also quoted. coefficient of variance A dimensionless measure of the dispersion of a random variable, calculated by dividing the standard deviation by the mean. cold working The plastic deformation of a metal at a temperature low enough to cause permanent strainhardening. The hardness and tensile strength are progressively increased with the amount of cold work, but the ductility and impact strength (toughness) are reduced. Cold working is the technique often used to obtain the necessary strength in the corrosion-resistant alloys, e.g., duplex stainless steel and the more highly alloyed austenitic stainless steels. conductor casing The first casing string which is fitted to the wellhead system and utilizes gas diversion for well control. CRA corrosion resistant alloy design formula A formula which, based on production measurements or specifications, provides a performance property useful in design calculations. A design formula can be defined by applying reasonable extremes to the variables in a limit state formula to arrive at a conservative value of expected performance. When statistically derived, the design formula corresponds to a defined lower percentile of the resistance probability distribution curve. EPT Drilling
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deterministic An approach which assumes all variables controlling a performance property are known with certainty. DLS dogleg severity dogleg severity wellbore curvature, expressed in degrees per length (100 ft., 30 m) DSOH deepest subsequent open hole DST drill stem test duplex stainless steel Stainless steel in which there is a two-phase structure of ferrite and austenite, normally present in balanced or near-balanced quantities (50%/50%). Typically these steels contain 22 to 25% chromium and 5 to 7% nickel e.g., 25 Chrome, Alloy 2205, Alloy 2507. elongation In tensile testing the extension of the test-piece when stressed to fracture, usually expressed as a percentage of a specified “gauge length” (e.g., x% on a gauge length of 2 in). Elongation is a measure of the ductility of the material. electric resistance weld (ERW) A tube forming process in which the cylindrical tube is made by forming a strip of metal into a tube and then joining the longitudinal edges by electric-resistance welding (ERW). In ERW the mating longitudinal edges are heated to high temperatures by a high-frequency induction heater. This resistance-heats just the edges which are then brought together and loading applied to form a weld, without any addition of filler metal to the weld. EMI electromagnetic inspection equivalent circulating density (ECD) The density of a fluid which, if it occupied a tube or its annulus, would create a pressure-at-depth equal to the pressure caused by an existing fluid, any solids suspended in the fluid and the dynamic effects of fluid flow. EW electric weld fatigue The failure of a material by fluctuating or repeated stresses having a maximum value below the material’s tensile strength. Fatigue failures often occur at loads which would not cause permanent damage if applied statically. The fracture process is usually progressive, i.e., it takes place over a number of load cycles. ferrite An iron or solid solution alloy of iron which has a body-centered cubic crystallographic structure. In steels, the solute is generally carbon. Carbon has low solubility in ferrite, being only some 0.02 wt %. ferritic stainless steel A low carbon steel, usually containing between 16 and 30% chromium. Ferritic stainless steels are rarely used downhole. Grain Size Metals are generally crystalline materials, with the individual crystals termed grains. When a material is cooled slowly from a high temperature, e.g., in casting, it will generally have a coarse grain size. The grain size can be reduced by alloying additions (grain refiners, e.g., aluminium additions to EPT Drilling
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steel), hot working and/or heat treatments (such as annealing). A smaller grain size will normally lead to greater strength, higher ductility and better toughness. FORM First Order Reliability Method FWS Functional Well Specification hardness The hardness of a metal is approximately related to its tensile strength. Therefore, hardness measurements can be used as a convenient non destructive inspection technique. The hardness of a metal is often measured by an indentation test. In the indentation test, a hard point is pressed into the material under a known load. The hardness is then judged from the size of the indentation. The most common types of hardness tests are: • The Brinell (HB) test in which a small hardened steel ball is used as the indenter and the diameter of the indent is measured; • The Vickers (HV) test in which a pyramidal diamond indenter is used and the size of the indent is measured across the corners; • The Rockwell (HRC) test in which a conical diamond indenter is used and the depth of the indent is measured. Tables to convert between these different test results are contained in ASTM E140. hardenability The relative ability of a ferrous alloy to form martensite when quenched. Hardenability is commonly measured as the distance below the surface at which the material exhibits a predetermined hardness (e.g., 50 HRC). HIC hydrogen induced cracking intermediate casing Casing strings or liners set after the surface casing but before the production casing.
iron carbide A compound of iron and carbon, e.g., Fe3 C (cementite). When a steel is cooled from high temperatures the solubility of carbon decreases. The carbon that is thus pushed out of solution reacts with iron to form iron carbides. Carbon steels often contain a proportion of iron carbide as a result of the very low solubility of carbon in ferrite. Label 1 An API/ISO substitute for size, preserving the US Traditional units outside diameter value in inches as a name to be used when referring to a tubular. Label 2 An API/ISO substitute for mass per length, preserving the US Traditional units value in pounds per foot as a name to be used when referring to a tubular. LC lost circulation limit state formula A formula which, when used with the measured geometry and material properties of a sample, produces an estimate of the failure value of that sample. A limit state formula describes the performance of an individual sample as closely as possible, without regard for the tolerances to which the sample was built. EPT Drilling
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LOT leak-off test martensitic stainless steel A group of hardenable stainless steels containing from 11 to 14% chromium and 0.15 to 0.45% carbon e.g., L80 13 Chrome. These steels harden readily on air cooling from about 950◦C (1750◦F). It is usually necessary to reintroduce some ductility by tempering. martensite If steels are cooled rapidly there is insufficient time for the carbon to be pushed out of solution to produce large carbide particles/platelets. Therefore, a metastable transitional constituent is produced known as martensite. This transformation product is hard/strong, but also brittle. In most cases it is necessary to reintroduce some ductility by tempering. mean expected value or weighted average monel A non-magnetic alloy containing nickel and copper. In the past this material was commonly used for non-magnetic drill collars (NMDCs). Hence, NMDCs are also known as “Monel” collars. However, this material has been superseded for NMDCs by highly alloyed austenitic stainless steels, beryllium copper alloys, etc. MPI magnetic particle inspection normalizing An annealing heat treatment followed by still air cooling. The purpose of normalizing is to refine the grain size, homogenize the structure and remove strains induced by mechanical working. OCTG oil country tubular goods PBR polished bore receptacle PDDP Pre-Drill Data Package pearlite A metastable lamellar aggregate of ferrite and cementite (F e3 C) produced by slow cooling austenite in carbon, low-alloy steels. Pearlite will only begin to be formed when the austenite contains a certain carbon content (about 0.87 wt-% for a Fe-C alloy). Therefore, most plain carbon steels when slowly cooled contain a mixture of ferrite and pearlite. precipitation hardening stainless steel Some materials will harden on cooling by the subsequent precipitation of a constituent from a supersaturated solid solution. This produces materials that can be hardened (strength increased) by heat treatment. One such group of materials is the precipitationhardening stainless steels, e.g., 17-4PH which contains 17% chromium and 4% nickel. PDF probability distribution function probabilistic method An approach which uses distributions of geometric and material property values to calculate a distribution of performance property values. production casing The casings or liners inside which the production tubing or test string is to be run. production tubing The tubing string used for production of hydrocarbons or water or gas injection. EPT Drilling
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proof stress The stress required to produce a predetermined plastic strain in the material, e.g., 0.2% proof stress. Proof stress is used in the specification of materials that do not exhibit a definite yield point. quenching A process of rapidly cooling a metal from an elevated temperature by contact with liquids, solids or gases. Typically, liquids are used, either aqueous or oil-based. Carbon and low-alloy steels are quenched to form martensite. reduction of area A measurement taken during tensile tests on materials. Reduction of area is the difference between the original cross-sectional area of the test piece and the minimum cross-sectional area after failure expressed as a percentage of the original area. It is a measure of ductility of the material.
SCC stress corrosion cracking seamless tubular A tubular made by a series of forging and rolling operations or extrusion processes, to produce a tube with no “seam” (i.e., no longitudinal weld). SMLS seamless SOR Statement of Requirements SRB sulphate reducing bacteria SSC sulfide stress cracking, a type of stress corrosion cracking stainless steel A corrosion-resistant type alloy steel which contains a minimum of 12% chromium. Chromium is the major element that confers upon the steel an ability to resist corrosion. This effect is attributed to the formation of a thin protective oxide on the metal surface. Corrosion resistance can be increased by the addition of other alloying elements, e.g., nickel, molybdenum, copper. The main types of stainless steel are austenitic, ferritic, martensitic, duplex and precipitation hardened. standard deviation A measure of dispersion or variability, i.e., the standard deviation is a measure of how closely the values of a random variable are clustered around the central value. stress relief heat treatment A heat treatment designed to reduce internal stresses in metals that have been induced by casting, quenching, welding, cold working, etc. The metal is soaked at a suitable temperature for sufficient time to allow readjustments in the stresses, then slow cooled. Stress relief does not intentionally involve any structural changes within the steel. submerged-arc weld (SAW) A tube forming process in which the cylindrical tube is made by forming a strip of metal into a tube and then joining the longitudinal edges by submerged-arc welding (SAW). SAW is arc welding in which the electric arc between the electrode and the work piece is shielded by a blanket of granular, fusible material. This shielding assists in the deposition of weld metal from the electrode (filler metal). structural conductor casing The casing cemented, jetted, or driven which provides structural support to the wellhead, BOP and tree. EPT Drilling
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surface casing The first casing string upon which a BOP stack is installed and well control procedures are planned with controlled circulation. synthesis method A probability approach which addresses the uncertainty and likely values of pipe performance properties by using distributions of geometric and material property values. These distributions are combined with a limit state formula to determine the statistical distribution of a performance property. The performance distribution in combination with a defined lower percentile determines the final design formula. tempering A heat treatment to which steels, especially low-alloy steels, are subjected in order to produce changes in the mechanical properties and structure. This process often follows quenching, which produces a steel that is often too hard and too brittle to be of practical use. In tempering, the steel is heated to a suitable temperature at which structural changes will occur which reduce hardness (strength) and increase toughness. This is followed by cooling at a suitable rate. When martensite is tempered, it gradually decomposes, with iron carbide being ejected from the solid solution (often called tempered martensite.) The result of full tempering is a structure consisting of ferrite in which the iron carbide is dispersed as fine particles. tensile strength The tensile strength is the maximum load sustained by test-piece during a tensile test divided by its original cross-sectional area. TVD true vertical depth USC US Customary (units) UT ultrasonic toughness The ability of a material to absorb energy and deform plastically before fracturing, thus limiting crack propagation. One method of measuring toughness is the Charpy test. However, this is an imprecise measure as it can only indicate the energy absorbed at a particular temperature with a particular notch shape when subjected to impact or sudden loading. The threshold stress intensity factor (KIC) is a more accurate measurement, as this can quantify the critical stress for a crack to grow in a manner that accounts for the geometry of both the crack and the component. However, KIC is a difficult factor to quantify, so Charpy testing is normally used as a routine quality control measure. VIV vortex induced vibration WPDP Well Planning Data Package WOC waiting on cement WSD working stress design yield strength The stress at which the material first exhibits permanent, inelastic deformation. Young’s modulus A constant defined as the ratio of stress to the corresponding strain in the elastic region of a tensile test. As such it is a measure of the rigidity of a metal. Young’s modulus is a material characteristic that is independent of strength level or heat treatment. EPT Drilling
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4.4.3
Symbols
Ab seal bore area in polished bore receptacle or expansion joint Ac empirical constant in historical, API collapse formulation Ai area of the pipe internal cross section, Ai = π/4d2 Ao area of the pipe external cross section, Ap = π/4D2 Ap area of the pipe cross section, Ap = π/4(D2 − d2 ) Asp area of specimen cross section Bc empirical constant in historical, API collapse formulation ~b unit binormal vector Cann compressibility of annulus formulation Cc empirical constant in historical, API collapse formulation c tube curvature, the inverse of the radius of curvature to the centerline of the pipe csnd sand concentration D specified pipe outside diameter Dh wellbore diameter Dtj tool joint diameter Dtool tool diameter DF design factor DFb burst design factor DFc collapse design factor DFt tension design factor DFv triaxial design factor d pipe inside diameter, d = D − 2t dwall inside diameter based on kwall t, dwall = D − 2kwall t E Young’s modulus ~ex unit vector in global x-direction ~ey unit vector in global y-direction EPT Drilling
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~ez unit vector in global z-direction FEA end action force FEAT end action force due to temperature FEAB end action force due to ballooning Fa axial force F~a axial force vector Fai initial axial force Fallow allowable axial force Fb additional axial force from bending Fbal tensile force created from a change in external pressures external pressure or fluid density from the initial condition Fbuoy buoyancy force, calculated as an upward (compressive) force acting on the bottom of the tubular, and a force on exposed shoulders in tapered strings Fc empirical constant in historical, API collapse formulation Fcr critical value of effective force for column buckling Fe effective force F~f distributed friction force vector Ff r tensile force created from fluid friction from high injection or production rates Fhk hook load Fop overpull available for pulling the tubular if this becomes necessary during running operations Fpkr piston load on expansion devices such as polished bore receptacles Fplug tensile force created by the surface pressure used to bump the plug and/or pressure held during WOC Fres residual tension Fshock force arising from sudden accelerations and decelerations during running Fs statistical correction for small datasets FT tensile force created from a change in temperature from the initial condition Fwt weight of the tubular in air below the point of interest fT temperature downrating factor EPT Drilling
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fumn minimum tensile strength, as specified in ISO 11960 or API 5CT fw wear factor fwear wear downrating factor fwt axial component of air weight per length fy yield strength fyax equivalent yield strength in the presence of axial stress fymn minimum yield strength, as specified in ISO 11960 or API 5CT Gc empirical constant in historical, API collapse formulation ~ i resultant of internal fluid pressure H ~ o resultant of external fluid pressure H h true vertical height hc true vertical height of cement column hm true vertical height of drilling fluid column hs true vertical height of spacer fluid column hsw true vertical height of salt water influx hw water depth I moment of inertia K axial stiffness Kcomp composite bulk modulus Kg gas bulk modulus kht hydrostatic test factor Kl liquid bulk modulus kwall factor to account for the specified tolerance of the pipe wall. For example, for a tolerance of minus 12.5%, kwall = 0.875 L length La annulus length Ldr length of drilled interval Lp length to packer EPT Drilling
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Ltool tool passage length δLT length change due to temperature m ˙ mass flow rate mf r formation fracture margin mtest test margin N normal (contact) force per length ~ normal (contact) force vector N Nj normal (contact) force per length on tool joint n number of samples ~ j normal (contact) force vector on tool joint N ~n unit normal vector P pitch of helix p pressure pAP B incremental pressure due to annular pressure build-up pa annulus pressure pb burst differential pressure pc equivalent collapse pressure pcr syntactic foam crush pressure pE pressure for elastic collapse pdes0,95 95% confidence design collapse strength, for a target reliability level of 0.5% pf r fracture pressure of formation pf ric friction pressure loss pf rN et net pressure in fracture pg gas (bubble) pressure pH2 S partial pressure of H2 S ph hydrostatic head pressure pht hydrostatic test pressure EPT Drilling
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pi internal pressure piSurf internal surface pressure piY AP I internal pressure at yield for a thin tube piY Lo internal pressure at yield for an open-end thick tube pml mudline pressure po external pressure pP pressure for plastic collapse pp pore pressure pres reservoir pressure ps spacer pressure pset packer setting pressure psys system pressure pT pressure for transition collapse ptrSurf surface treating pressure pY pressure for yield collapse Q non-uniform distributed load ~ resultant of all distributed weight and hydrostatic loads Q q volumetric flow rate R non-uniform line load RT transition slenderness ratio Rc radius of curvature, the inverse of curvature Rp rate of penetration r radial coordinate, dwall /2 6 r 6 D/2 rc radial clearance s distance along string (measured from the bottom of the string, upward T temperature TBHC bottom hole circulating temperature EPT Drilling
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TCmt ”as cemented” temperature TC drilling circulating temperature TCx points used to construct drilling circulating temperature, x = 1, 2, 3 TBHCmt bottom hole ”as cemented” temperature TBHS bottom hole static (undisturbed) temperature TC drilling circulating temperature Tf final temperature Tg gas (bubble) temperature Ti initial temperature Tml mudline temperature TP producing temperature TS static (undisturbed) temperature TSurf static surface temperature TSurf Cmt surface ”as cemented” temperature TSurf P surface producing temperature Ts spacer temperature TT D static (undisturbed) temperature at total depth t specified pipe wall thickness, time (depending on context) tE wall thickness loss due to erosion Ua annular velocity ~t unit tangent vector V volume Vg volume of gas Vl volume of liquid Vml volume at mudline Vo external volume of pipe segment, Vo = Ao ds Vs volume of spacer EPT Drilling
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v velocity vr reduced velocity vw current or wave velocity wa air weight per length we effective weight per length xH2 S mole fraction of H2 S in gas expressed z true vertical depth (TVD) zDSOH true vertical depth (TVD) of deepest subsequent open hole zf true vertical depth (TVD) in formation zLC true vertical depth (TVD) to top of lost circulation zone zm true vertical depth (TVD) to top of drilling fluid zres true vertical depth to reservoir zs true vertical depth to casing shoe zsh true vertical depth to bottom of shallow temperature gradient zw true vertical depth (TVD) to mudline α inclination αT coefficient of linear thermal expansion αV T coefficient of volumetric thermal expansion β azimuth γc cement weight density γcf cement weight density γds drilled solids weight density γe equivalent drilling fluid weight density γf formation weight density (equivalent drilling fluid density) γf r fracture gradient γg gas weight density, gas gradient γm drilling fluid weight density EPT Drilling
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γi internal fluid weight density γmds drilling fluid weight density including drilled solids γLOT leak-off test equivalent drilling fluid weight density γo external fluid weight density γS steel weight density γs spacer weight density γsw sea water weight density γT temperature gradient γT sh temperature gradient in shallow interval below mudline εel the minimum gauge length extension in 50.8 mm (2.0 in.) in percent rounded to the nearest 0.5% below 10% and to the nearest unit percent for 10% and larger εu ultimate strain µ coefficient of friction or mean, depending on context µp plastic viscosity µs mean of dataset ν Poisson’s ratio ω rotary speed ωn natural frequency ρC radius of gyration σ standard deviation σa component of axial stress not due to bending σb component of axial stress due to bending σdev component of axial stress due to deviation σe equivalent stress σh circumferential or hoop stress σhi circumferential or hoop stress at r = dwall /2 σho circumferential or hoop stress at r = D/2 σhb component of axial stress due to helical buckling EPT Drilling
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σob overburden stress σr radial stress σri radial stress at r = dwall /2 σro radial stress at r = D/2 σs standard deviation of dataset σte horizontal tectonic stress σyp yield point of mud () average of (), usually over length
4.4.4
Units and Conversions
Three different unit systems are commonly used within BP: • US Customary (USC) units, otherwise referred to as oilfield units; • Hybrid units, essentially USC units with SI lengths, used in most of the world outside the United States, Canada and Russia; • SI units, currently used only in Canada and Russia. Table 4.1 summarizes key variables and the units used for those variables in the various unit systems.
Table 4.1. Unit Usage Variable
Symbol(s)
US Custom-
Hybrid Unit
SI Unit
ary Unit Angle
α, β
◦
◦
◦
Axial length
L, La , Ldr , Lp , Ltool , δLT , P , s
ft.
m
m
Coefficient of Thermal Expan-
αV T , αT
1/◦ F
1/◦ C
1/◦ C
sion Cross-sectional
Ab , Ai , Ao , Ap , Asp
in2
in2
mm2
area Compressibility
Cann
psi−1
psi−1
MPa−1
Concentration Curvature
csnd c
% ◦ /100 ft
% ◦ /30 m
% ◦ /30 m
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Variable
Symbol(s)
US Custom-
Hybrid Unit
SI Unit
in. lbf
in. lbf
mm N
Fres , Fshock , FT , Fwt fwt , K, N , Nj , R, wa , we
lbf /f t
lbf /m
N/m
ary Unit Diameter Force
D, Dh , Dtj , Dtool , d, dwall FEA , FEAT , FEAB , Fa , Fai , Fallow , Fb , Fbal , Fbuoy , Fcr , Fe , Ff r , Fhk , Fl , Fop , Fpkr , Fplug ,
Force per length Frequency
ω, ωn
1/s
1/s
1/s
Moment of Inertia
I
in4
in4
mm4
Limit stress Mass flow rate
fumn , fy , fyax , fymn m ˙
psi lbm /s
psi lbm /s
MPa kg/s
Mass per length Pressure or
N/A Cc , mf r , mtest , p, pAP B , pa , pb ,
lbm /ft psi
lbm /ft psi
kg/m MPa
stress
pc , pcr , pdes0,95 , pE , pf r , pf ric , pf rN et , pg , pH2 S , ph , pht , pi ,
Radial length
σro , σte , σyp r, rc , t, tE , ρC
in.
in.
mm
Radius of curva-
Rc
ft.
m
m
ture Rate of penetra-
Rp
ft/h
m/h
m/h
tion Stiffness
E, Kcomp , Kg , Kl
psi
psi
MPa
Strain Temperature
εel T , TBHC , TCmt , TC , TCx ,
% ◦ F
% ◦ C
% ◦ C
piSurf , piY AP I , piY Lo , pml , po , pP , pp , pres , pset , ps , psys , pT , ptrSurf , pY , Q, σa , σb , σdev , σe , σh , σhi , σho , σhb , σob , σr , σri ,
TBHCmt , TBHS , TC , Tf , Tg , Ti , Tml , TP , TS , TSurf , TSurf Cmt , Temperature
TSurf P , Ts , TT D γT , γT sh
Gradient Time
t
s
s
s
True vertical depth or height
h, hc , hm , hs , hsw , hw , z, zDSOH , zf , zLC , zm , zres , zs ,
ft.
m
m
◦
F/100 ft
◦
C/30 m
◦
C/30 m
zsh , zw Continued on next page EPT Drilling
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Variable
Symbol(s)
US Custom-
Hybrid Unit
SI Unit
ary Unit Velocity Viscosity
Ua , v, vw µp
ft/s cp
m/s cp
m/s cp
Volume Volumetric flow
V , Vg , Vl , Vml , Vo , Vs q
ft3 gal/min
m3 m3 /min
m3 m3 /min
rate Wear factor
fw
gal/min
m3 /min
m3 /min
Weight
density
γc , γcf , γds , γe , γf , γf r , γg , γm ,
lbf /gal
SG
kg/m3
density
γi , γmds , γLOT , γo , γs , γsw γS
lbf /in3
lbf /in3
N/m3
(fluid) Weight (solid)
Table 4.2 summarizes the units used in this manual and conversion factors between elements of the USC and SI unit systems. Table 4.2. Units and Unit Conversion Unit
Multiplied By
= Unit
Multiplied By
= Unit
() per 100 ft ◦ F per 100 ft
0.9842519685 0.5468066492
() per 30 m ◦ C per 30 m
1.016 1.8288
() per 100 ft ◦ C per 100 ft
barrel (bbl)
0.1192404712
cubic meter (m3 )
8.3864143603
barrel (bbl)
foot (ft) foot (ft)
30.48 0.3048
centimeter (cm) meter (mm)
0.032808 3.2808
foot (ft) foot (ft)
foot (ft)
304.8
millimeter (mm)
0.0032808
foot (ft)
foot-pound force (f-lbf )
1.3558179
Joule (J)
0.73756217557
foot-pound force (f-lbf )
1.3558179
Newton-meter (N-m)
0.73756217557
foot-pound force (f-lbf ) foot-pound force (f-lbf )
inch (in.) inch (in.) inch (in.)
2.54 0.0254 25.4
centimeter (cm) meter (mm) millimeter (mm)
0.3937 39.37 0.03937
inch (in.) inch (in.) inch (in.)
kilogram force (kgf )
9.80665
Newton (N)
0.1019716213
kilogram force (kgf )
pound force (lbf )
4.4482216
Newton (N)
0.22480894387
pound force (lbf )
pound force per foot (lbf /ft)
14.59390289
Newton per meter (N/m)
0.06852176609
pound force per foot (lbf /ft)
pound force per square inch (psi) pound force per square inch (psi)
0.06804595706 0.0689475728
atmosphere (atm) bar (bar)
14.69595025 14.50377380
pound force per square inch (psi) pound force per square inch (psi)
pound force per square inch (psi) pound force per square inch (psi) pound force per square inch (psi)
6.89475728 0.00689475728 6,894.75728
kiloPascal (KPa) megaPascal (MPa) Pascal (Pa)
0.14503773801 145.03773801 0.00014503773801
pound force per square inch (psi) pound force per square inch (psi) pound force per square inch (psi)
pound force per cubic inch (lbf /in3 )
27,679.90471
kilogram force per cubic meter (kgf /m3 )
3.6127292 × 10−5
pound force per cubic inch (lbf /in3 )
pound force per square inch per foot (psi/ft)
0.02262059475
megaPascal per meter (MPa/m)
44.20750254
pound force per square inch per foot (psi/ft)
pound mass (lbm )
0.45359237
kilogram (kg)
2.204622622
pound mass (lbm )
pound mass per foot (lbm /ft)
1.488163944
kilogram per meter (kg/m)
0.6719689752
pound mass per foot (lbm /ft)
pound mass per gallon (US) (ppg) pound mass per gallon (US) (ppg)
119.8264273 0.1198264273
kilogram per cubic meter (kg/m3 ) specific gravity (SG)
0.008345404452 8.345404452
pound mass per gallon (US) (ppg) pound mass per gallon (US) (ppg)
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Note the following in Table 4.2: • An alternate abbreviation for pound mass per gallon (US) is lb/gal. • 1 ppg = 0.051948 psi/ft, 1 SG = 0.43353 psi/ft • A Pascal is 1 Newton per square meter. • To convert from Fahrenheit (◦ F) to Centigrade (◦ C), see Equation 14.1. To convert from Centigrade (◦ C) to Fahrenheit (◦ F), see Equation 14.2. In the manual, when the use of conversion factors, for example between density and pressure gradient, might cause confusion, the equation in question will be presented in all three unit systems, in the order US Customary, Hybrid, SI. For example, the relation between density and hydrostatic pressure at a true vertical depth z is, in US Customary units,
p [psi] = γm [ppg] × hm [ft TVD] × 0.052,
(4.1a)
p [psi] = γm [SG] × hm [m TVD] × 1.4206,
(4.1b)
p [MPa] = γm kg/m3 × hm [m TVD] × 9.80665 × 10−6 .
(4.1c)
or in Hybrid units,
or in SI units,
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Chapter 5
Data Needed Before Design 5.1
Functional Well Specification
Drilling must ensure that the Functional Well Specification (objective) is met for each well. A Functional Well Specification (FWS), also known as a Well Statement of Requirements (Well SOR), defines the intended objective of the well for the asset and should contain sufficient detail to determine the optimum casing and/or tubing design and well plan. FWS objectives may not always be accomplished by the lowest cost per foot drilling operation; therefore, an FWS should be agreed upon prior to detailed well planning. Drilling’s early involvement in defining the FWS is essential to ensure that maximum value is added to the business at the conceptual stage of discussions with the asset. The areas of an FWS that directly impact casing and tubing design should be addressed prior to the actual well planning. Listed below are areas of the FWS that impact casing and tubing designs: • Well location, total depth, water depth and objective depth(s). • Deviation of the wellbore. • Designation as exploration or development well–the probability of completing as a development well significantly impacts both casing design and material selection. Serious discussions should precede any well being designated exploration-only. The expense and risk associated with converting an explorationonly well to a development well may be prohibitive. • Timing requirement, which impacts rig availability and long lead items. • Evaluation requirements (logging, coring, or testing), which impact hole size and mud types. • Testing or production rates required, which impacts the sizing of tubing and production casing. As the tubing size is selected to optimize well productivity, all outer strings, beginning with the production casing, are sized depending on the tubing diameter. • Hydrocarbon composition–gas or oil? Corrosion anticipated from H2 S/CO2 /Cl impacts material selection, cost and lead time for tubulars. EPT Drilling
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Well Name:
Location:
Water Depth:
Operating Group:
Date:
Originator:
Contact Number:
Team Members:
Contact Number:
Exploration Well Development Well
Area of Responsibility:
Well Spud Date Estimate: Well Evaluation Data Required By: Well Production Required By:
WELL OBJECTIVE
Primary Objectives:
Secondary Objectives:
For Exploration Wells – Is well a potential producing candidate?
A. Total Depth (TD):
(True Vertical Depth)
Directional Well Planning Details:
WELL DETAILS
B. Anticipated Pore Pressure at TD:
D. Hydrocarbon Composition: Corrosive Equipment:
C. Anticipated Bottom Hole Ttemperature:
Oil
Gas
CO2
H2S
Unknown
E. Hazards or Lease Constraints:
F. Testing or Producing Rates Required:
G. Testing or Producing Life Expectancy:
H. Nearest Offset Well Location:
BOPD
SCFD
I. Miscellaneous Comments:
Approved by:
Figure 5.1. Sample Functional Well Specification (FWS).
• Producing life of well and completion design’s intervention procedures. Particular attention should be paid to completion aspects of the well life, such as clearance for an SSSV or possible artificial lift, the potential for multiple/dual completions, provision for washing over tubing and the potential for exploration deepening. Figure 5.1 provides a pro forma starting point for establishing an FWS. EPT Drilling
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5.2
Pre-Drill Data Package
A key component in developing the casing design for a well is the Pre-Drill Data Package (PDDP), also known as a Well Planning Data Package (WPDP). The pre-drill data package must be completed before a well plan and tubular design can be generated. This data package should include the information provided below: • Functional Well Specification, included for reference. • Geological information (formation tops, faults, structure maps, etc.). • Pore pressure and fracture gradient profiles. • Offset well data (casing and tubing programs, geological tie-in, operational problems, drilling fluid densities, etc.). • Hazards and constraints (shallow gas, lease line restrictions, faults, rig if selected, BOP size, equipment import restrictions, casing stocks, etc.). • Undisturbed temperature profile. • Target(s) and proposed intersecting well trajectory. • Anticipated production/injection rates and fluid composition(s). • Downhole completion component sizes. • Annulus communication, bleed off and monitoring policies (particularly applicable to development wells).
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Chapter 6
Tubular Design Software in BP 6.0.1
Safety Critical Software
Casing and tubing design software are safety critical. Standards for safety critical software shall be maintained in every BU to address the key areas of implementation, fault tracking and the use of software. Such standards may originate at the stream or corporate level, however each BU shall possess a management process to assure specifications, design, program changes, documentation, testing and acceptance requirements are met. Before the release and distribution of any new or revised safety critical software, a defined plan shall be in place addressing the business case and responsibilities for implementation. A system shall be in place to report, categorize, prioritize and resolve software bugs, as well as properly record and track critical faults. The responsibility for this system shall lie within each BU.
6.1
Introduction
Software tools exist in BP to facilitate the proper implementation of the BP Tubular Design Manual. As with other areas of engineering, performing hand calculations on simple examples is a valuable aid to understanding, but it is recommended that software specifically tailored to tubular design be used for actual design work. This saves time, promotes consistency and reduces scope for errors. The applications available are: • CasingSeat–option generation and setting depth determination. • StressCheck–casing design and analysis (but not tubing1 ). • WellCat–casing and tubing analysis, with more analytical options than StressCheck. Wellcat has five components called Drill (drilling temperature modeling), Prod (production temperature modeling), Casing (advanced casing design), Tube (tubing design) and MultiString (annular pressure buildup and wellhead movement). 1 StressCheck
will perform simple analyses of tubing latched in a packer. However, all serious tubing modeling should be performed in Wellcat.
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• CWear–casing wear prediction.
6.2
The Software Packages
All of the software packages discussed here are available from BP’s common operating environment and are available through appropriate Help Desk channels. The approved BP release of each product is recommended, as use of this version ensures trouble free data exchange with other BP engineers.
6.2.1
CasingSeat
This Landmark product is the commercialization of BPX R&D performed in the period 1992 to 1994. It is intended to generate multiple casing schemes, that is, combinations of hole and casing sizes, which satisfy operational constraints such as permissible overbalance, kick tolerance, and competence at specific depths. The mechanical design aspects of these schemes can then be analyzed using StressCheck.
6.2.2
StressCheck
StressCheck is a Landmark product intended to be an easy-to-use application suitable for casing design on the majority of wells. While suitable for most wells there are some aspects that it either does not cover or only deals with in part. These aspects include: • Temperature calculation • Complex designs • Annular pressure buildup analysis • Wellhead movement • Friction effects • Connection design • Material selection for sour service. The following sections address each of these aspects, respectively. 6.2.2.1
Temperature Calculation
StressCheck provides a set of default casing temperature profiles intended to result in a generally conservative design. Tensile loads resulting from temperature changes affect axial and triaxial results and the collapse derating associated with tension. In addition to determining the effect of temperature change on axial load, StressCheck’s temperature profiles are also used to derate yield strength and consequently the casing’s burst, collapse and tension ratings, provided the Temperature Deration option is selected on the Tubular menu’s Design Parameters dialog. The temperature deration box in StressCheck should always be checked. EPT Drilling
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The load lines appearing in StressCheck’s design plots may be based on several load cases that have different worst-case temperature profiles. Hence, the temperature deration effect as a function of depth may be based on several temperature profiles. The profiles are used for gas density calculations if a “gas gravity” option is used in the drilling and production load cases. The temperature profiles are based on whether the load case is a drilling, production, or running and cementing load: • Drilling Loads–All drilling load profiles are determined from the API circulating temperature at a depth that is noted in the discussion of the individual loads. A linear temperature profile is constructed which intersects the circulating temperature and the mid-point of the undisturbed temperature profile. If the API circulating temperature is less than the mid-point temperature, a constant temperature equal to that of the mid point is used. • Production Loads–These temperature profiles are either production or injection profiles. The production temperature profile consists of a constant temperature equal to the undisturbed temperature at the perforation depth specified on the Production Data dialog. The injection temperature profile is used only for the Injection Down Casing burst load case and consists of a constant temperature equal to the surface temperature. • Running and Cementing Loads–The load cases specified on the Axial Loads dialog are running and cementing loads. All these loads assume a drilling temperature profile based on circulation at the casing shoe depth. Although the defaults are as above, the user can enter temperature profiles obtained from measurements or prediction software (e.g., Wellcat). For most wells StressCheck’s assumptions represent reasonable temperature profiles, tending toward conservatism in burst cases. For high-temperature applications, however, the reservoir temperature assumption for production casing may be overly conservative, particularly for an exploration or appraisal well not intended for long-term production. For these applications it may be appropriate to use temperature predictions from Wellcat, in which case it may be as easy to complete the design using the Wellcat Casing module as to transfer data to StressCheck. For collapse loads, the static temperature profile is usually more conservative than the StressCheck default. 6.2.2.2
Complex Designs
StressCheck does not include options for cementing. It allows a single-stage cementation with a maximum of two slurries (lead and tail). It also allows a single pick-up or slack-off force to be included in the landing conditions. For slack-off, load transfer in StressCheck is actually presumed to occur below the top of cement. For stage cemented casings, StressCheck may provide an incorrect initial axial force (due to inappropriate buoyancy assumptions) and will not allow redistribution of axial forces through the uncemented interval between the top of the first stage and the bottom of the second stage. Similarly, although liner packer equipment may be modeled by entering a liner top depth less than the liner top of cement depth, StressCheck assumes that the full buoyed weight of the liner is hung off at the liner top depth. EPT Drilling
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Finally, while StressCheck allows the specification of a common gas-lift design case (full evacuation of the production casing to atmospheric pressure), it is not possible to enter a point axial load applied in the uncemented casing as would occur with an annulus safety system (or other mid-string tubing hanger) installed. For any of these situations it is advisable to check the design using the Casing module of Wellcat, which allows such geometries and loads to be specified. 6.2.2.3
Annular Fluid Expansion Analysis
Increases in temperature after casing is landed can cause thermal expansion of fluids in sealed annuli and can result in significant pressure loads. Most of the time these loads do not need to be included in the design because the pressures are bled off as part of an asset’s Annulus Monitoring policy. In subsea wells, however,the outer annuli cannot normally be accessed after the hanger is landed. Annulus expansion pressures can be large; StressCheck does not consider them. Wellcat does perform annular expansion calculations in its MultiString module. For guidance in APB/AFE calculations, consult EPT. 6.2.2.4
Wellhead Movement
StressCheck assumes that all casing strings are fixed at the wellhead and the top of cement. For an offshore well with a surface wellhead this is not strictly true. The wellhead is free to move vertically, constrained by the axial stiffness of the casing system between the mudline and the wellhead. Normally the assumption of a fixed wellhead datum is conservative, leading to over estimation of the axial load on each casing regardless of load case. This is true for all casings except the load-bearing casing on which the wellhead is installed. This string will be subject to a compressive load as each inner string, completion tubing and piece of wellhead equipment is landed, and the string may be subject to a significant tensile load while a well is producing. The simplified axial compressive loading check in StressCheck is not sufficient for platform conductor design and specialist advice should be sought. For high-temperature designs, the use of “single string” analysis (i.e., no wellhead movement) may be unnecessarily conservative. In these circumstances, specialists in EPT should be contacted to either perform or guide the calculation. The MultiString module of Wellcat does contain a Wellhead Movement option. Care should be exercised in applying this option, as the model assumes that all cemented casing is rigid, thus ignoring both the thermal expansion and mechanical compliance of the surrounding soil. For subsea wellheads, significant wellhead movement can occur even if the surface casing is cemented to the mudline. 6.2.2.5
Friction Effects
StressCheck does not include the effect of friction on casing and the corresponding variation in axial load along the length of the casing. Usually friction is not a significant issue in design, although it may be in considering whether a casing can be run in particular circumstances. It is possible to include an additional tension or compression by entering a pick-up or slack-off force under the landing conditions. These forces must be calculated using another application such as a drillstring simulator or the Torque Drag module of WellPlan. These inputs only influence axial loads for service loads and will not affect the casing axial loads EPT Drilling
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for installation load cases such as the running load, overpull or green cement (bump-plug) pressure test. For a pick-up (last movement in upward direction), the additional tension is applied as an additional axial tension above the top of cement only. For a slack-off (last movement in downward direction), the reduced tension/increased compression is applied along the whole casing length. Unfortunately, no help is provided in this instance by Wellcat. Although the Wellcat interface implies a friction calculation option, Landmark does not currently recommend its use. 6.2.2.6
Connections
StressCheck currently has limited connection analysis facilities and designs for pipe body only. Use the connection selection flowchart for guidance on suitable connections for a particular design. 6.2.2.7
Material Selection for Sour Service
Consult Chapter 18 for H2 S Service. The design option in StressCheck does not consider the effect of H2 S on grade selection; for example, it can suggest using Grade Q125 in an environment for which it is unsuitable.
6.2.3
WellCat
Although the above section describing what StressCheck doesn’t do may seem lengthy it is nearly always the case that a satisfactory design can be produced with StressCheck. In general Wellcat can address many of the issues described above which StressCheck can not. In addition it can perform tubing analysis, e.g., movement in packers, and provides extensive temperature prediction capabilities for drilling and production operations. WellCat’s increased capabilities come at the expense of complexity and reliability. The Windows interface for Wellcat continues to be bug-ridden. All input and output should be checked repeatedly to ensure that the software is correctly interpreting input data and that calculated results properly reflect the activity being modeled. 6.2.3.1
Tubing Design with WellCat
Wellcat is currently BP’s only software tool for tubing design. The Tube module of Wellcat readily interacts with the Prod module to provide a useful combination of operational temperature predictions and associated load cases pertinent to tubing design. When a tubing design with Wellcat is initiated, and if a casing design has been performed with StressCheck, it is often useful to employ Landmark’s data exchange feature (File/Data Exchange/Import or Export) to populate a number of Wellcat’s input fields, ensuring combatable input between the well’s casing and tubing designs.
6.2.4
CWear
Maurer Engineering’s CWear uses the soft string model (common in torque-drag software) along with a database of wear behavior coefficients collected from numerous experiments to predict casing wear from rotary drilling. CWear does not: EPT Drilling
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1. Compute tool joint wear. 2. Compute wear due to effects other than rotary drilling (e.g., due to sliding drilling or due to axial movement of logging wire lines). 3. Calculate properly the effect of wear on burst and collapse resistance. In the case of both these failure modes, the loss in resistance is directly proportional to the loss in wall thickness, rather than the estimates provided by CWear. In spite of these shortcomings, CWear is the only currently available means of computing casing wear, and its use is recommended.
6.3
Using the Software
The Casing Design school taught in Aberdeen and Houston (and local to a BU on request) provides incontext training in StressCheck and CWear. A “Tubing Stress Analysis and Wellcat” course offered at the BP/Chavron Drilling Training Alliance provides training in Wellcat. A short example of CasingSeat is included in the Casing Design school, but proper use of the software is not taught in any current BP school.
6.3.1
CasingSeat
CasingSeat is a useful first step in the casing design process in that it aids in selecting two important geometric characteristics of each casing string–length and diameter. Length is determined by the casing seat(s) necessary to provide a safe drilling environment to well TD, particularly drilling fluid density. Diameter is based on acceptable clearances between successive casings, as input by the user. The available combinations of diameter for successive casings can be a source of frustration, as the number of permutations of diameter grows as the product of available choices for each size. Nevertheless, this output feature can be ignored until a final sizing decision, allowing the user to concentrate on the more important subject of casing length/setting depth.
6.3.2
StressCheck
StressCheck is the heart of BP’s casing design toolkit. The software is highly interactive and will handle a variety of design issues, excepting those detailed in Section 6.2.2. StressCheck is taught as part of the Casing Design school offered several times a year (Aberdeen, Houston, and on request at any Business Unit) through the BP/Chevron Drilling Training Alliance. 6.3.2.1
Design and Analysis
StressCheck is capable of both design and analysis. The analysis function compares an existing, user-supplied tubular string to load conditions assumed to occur at various times in the life of the well. The design function attempts to assemble the lowest cost tubular string that will just meet the demands of the load conditions and associated design factors. EPT Drilling
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6.3.2.2
The BP Template
To aid in using StressCheck to design to the BP standard design loads, safety factors and inventory, the default template (normal.sct) supplied by Landmark has been supplemented by a template that resets program defaults to conform to this manual2 . When beginning a new design, select File/New and, instead of choosing to use the “normal” template, choose “bp2001v2”. If this template does not appear as a template option, contact EPT for assistance. By starting each design with the BP template, design of the following strings: • Conductor casing • Surface casing • Intermediate casing and liner • Production casing, liner and tieback will access preset defaults for design factors, analysis options, minimum cost design envelope, burst loads, collapse loads, axial loads and pipe inventory. This will not only ease input and lessen the chance of an input error or oversight but will also standardize both load cases and inventory. The latter feature can have significant economic impact on BP’s tubular procurement process. Typically, the cost of a tube will depend on, among other factors, its grade. For locations outside the United States, however, the global alliance between BP and Sumitomo effectively eliminates cost distinction based on grade. For this reason, it is advantageous to purchase L-80 in preference to N-80 due to the former’s superior metallurgical characteristics. Manipulation of the cost factors in StressCheck (Tools/Defaults/Cost Factors) is not recommended. Further, the factored cost is relative between designs by percentage, but may not be accurate for AFE budgets. 6.3.2.3
Input Guidelines
StressCheck is installed with an extensive, well-written Help file that serves as the user manual for the product. There are, however, supplemental comments worth including to aid a new user in his exposure to the product. The following sections augment StressCheck’s Help file to give additional guidance on input for design. 6.3.2.3.1
File
2 To
accommodate the standardized requirements of Deepwater Gulf of Mexico, a separate template for that SPU also exists. The DW GoM template is very similar to the primary BP template, but only includes DW GoM standard tubulars.
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Figure 6.1. StressCheck File Menu and Commands
Table 6.1. Input Tips and Guidelines for the StressCheck File Menu Menu Option
Input Tip/Guideline
New
When starting a new design, selecting the BP template will automatically set your design with:
• Recommended load cases • Recommended design factors • The standard BP Inventory • Recommended temperature deration factors.
Data File tions
Loca-
This option is available when no input files are open, e.g., when StressCheck is initiated, and is used to ensure that the software is pointing to the proper auxiliary data files. It is not normally necessary to access this command.
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Menu Option
Input Tip/Guideline
Import...
Aside from transfer of information via the underlying EDM database, StressCheck allows transfer of files outside the EDM environment. File types that may be imported include:
• SCK File... particularly StressCheck files created from pre-EDM versions of StressCheck. Caution should be taken in that transferring a file into the EDM environment may cause loss of some data or features (e.g., tabs).
• Wellpath... StressCheck is expecting a delimited plain ASCII file, using any combination of spaces, tabs, or commas as field delimiters. The expected entries in the table are measured depth, inclination and azimuth.
• Transfer File... StressCheck files created within the EDM environment, but related to an EDM database for which access may be unavailable.
Export...
Aside from transfer of information via the underlying EDM database, StressCheck allows transfer of files outside the EDM environment. File types that may be exported include:
• SCK File... a StressCheck file independent of the EDM environment. • Transfer File... a StressCheck file that may be transferred to an EDM database for which access may be unavailable.
Data Exchange
Data exchange occurs between StressCheck and other Landmark software. This command will probably be discontinued when Landmark completes implementation of the Engineering Data Model (EDM), allowing all Landmark applications to access a common database. Until that time, the Data Exchange command remains the best means of transferring StressCheck data to Wellcat (and vice versa).
Send
The Send command provides a shortcut to Microsoft Exchange for easy electronic transmission of a StressCheck file via email.
Properties
This command allows additional cross-referencing information to accompany a design and is recommended for anyone continually using the software. Such input as keywords can prove invaluable in organizing a large number of StressCheck files. For less extensive collections of StressCheck executions, a Comments tab is also provided under the Wellbore/General command which may suffice.
All other commands under the File menu are common to the Windows environment.
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Figure 6.2. StressCheck Edit Menu and Commands
6.3.2.3.2
Edit Table 6.2. Input Tips and Guidelines for the StressCheck Edit Menu
Menu Option
Input Tip/Guideline
Import
StressCheck allows commonly used and customizable features, such as pipe inventories and
From/Export
connection properties, to be stored in a catalog. The contents of such a catalog may be
To Catalog
accessed or altered during program execution.
Nominal Thickness
Wall
The default wall thickness derating for the calculation of API internal yield pressure is 0.875, which may be changed with this command, by individual grade, if desired. StressCheck’s acceptance of the change can be viewed on the Pipe Inventory command of the Tubular menu (Table 6.4) under the column “Wall Thick. (% of Nom.)”. The only performance property altered by this value is API internal yield pressure, viewed on the Pipe Inventory command of the Tubular menu under the column “Burst”. The default value should not be altered unless specific provisions are in place with the mill supplying the target string to guarantee the altered wall thickness.
Properties
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The properties of the active window can be altered.
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Figure 6.3. StressCheck Wellbore Menu and Commands
6.3.2.3.3
Wellbore Table 6.3. Input Tips and Guidelines for the StressCheck Wellbore Menu
Menu Option
Input Tip/Guideline
Casing and Tubing
Casing strings should be entered in the order in which they are run, not, for example, in
Scheme
descending order according to outside diameter. A liner will therefore appear in the casing scheme list prior to its corresponding tieback. StressCheck will currently only handle two well types–platform wells, for which all casing strings terminate at the surface, and subsea wells, for which all casing strings terminate at the mudline. Hybrid well designs, such as TLPs and SPARs, for which some casing strings terminate at the surface, and some strings terminate at the mudline, cannot be addressed. In fact, the error checking in StressCheck will strictly prohibit such casing schemes. Each spreadsheet row needs every cell completed in order to be recognized as valid data by StressCheck.
Pore Pressure
You must enter a pore pressure profile to execute a design or analysis.
Fracture Gradient
You must enter a frac gradient profile to execute a design or analysis.
Squeezing
This optional spreadsheet can be used to apply a uniform compressive load over an interval,
Salt/Shale
but this approach may result in a non-conservative design [78]. If interaction between the casing and a mobile formation is anticipated, special design considerations are in order and should be addressed outside the context of StressCheck. For example, see Section 8.4.2.2 for a discussion of collapse design in the presence of non-uniform loading. Use of this option for BP designs in the presence of formation mobility is not recommended.
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Figure 6.4. StressCheck Tubular Menu and Commands
6.3.2.3.4
Tubular Table 6.4. Input Tips and Guidelines for the StressCheck Tubular Menu
Menu Option
Input Tip/Guideline
Design Parameters
Always enable the Buckling and Temperature Deration options. These options are automatically enabled in the BP template and should not be disabled.
Initial Conditions
The density of the mix-water is used in some calculations for back-up pressure in cemented intervals. The density of the slurry is used to determine the hydrostatic pressure acting at the lower end of the casing during WOC. There is no option for allowing the hydrostatic pressure of the cement column to approach pore pressure during WOC.
Minimum Cost
Be very careful with the Design tab. Refer to Section 3.3.2.4 (3) “Special Notes” for more details on this feature. Cost in StressCheck does not automatically include connections. Connection cost is entered under Tubular/Special Connections. Cost values are approximate and do not exactly match the BP global alliance with Sumitomo (refer to Section 3.3.2.2).
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Menu Option
Input Tip/Guideline
Burst Loads
When choosing one of the default load cases, Drilling Loads can be selected when the current casing shoe is shallower than the well depth. Production Loads can be selected if the casing name (see Wellbore/Casing Scheme) is Production. To design production casing for both drilling and production loads, enter a well depth (Wellbore/General) that is one foot/meter deeper than the shoe of the production casing.
Collapse Loads
When choosing one of the default load cases, Drilling Loads can be selected when the current casing shoe is shallower than the well depth. Production Loads can be selected if the casing name (see Wellbore/Casing Scheme) is Production. To design production casing for both drilling and production loads, enter a well depth (Wellbore/General) that is one foot/meter deeper than the shoe of the production casing.
Axial Loads
Always enable the Service Loads option. This option is automatically enabled in the BP template and should not be disabled.
Custom Loads
Input of custom loads for a deviated (particularly horizontal) wellbore is inconvenient. Since the pressures and temperature profiles are referenced to measured depth, with linear interpolation between points, a large number of points should be supplied to ensure accuracy of the profile. Custom loads are also hampered by the fact that any change in the well can affect the pressures and/or temperatures used in generating the load profile, thus requiring a recalculation of the profile. Often one of StressCheck’s built-in loads can be manipulated to create the desired custom load. This alternative should always be pursued prior to using Custom Loads, as the built-in loads automatically adjust to changes in the well (e.g., changes to the well trajectory). To emphasize this point, consider modeling a well control scenario that might (if it existed) be labeled “Frac @Shoe w/Water Gradient Above.” Such a load case can be created by the following sequence:
• Under Tubular/Burst Loads, select the load case “Frac @Shoe w/Gas Gradient Above.” • Using the Edit tab, access the input data for “Frac @Shoe w/Gas Gradient Above.” • Use the combo box to change gas specification from Gas Gravity to Gas Gradient. • Enter a gradient (e.g., 0.433 psi/ft for fresh water) corresponding to water. Using such work-arounds can easily generate a variety of custom-like loads in StressCheck. It is important, however, to always plot the resulting load profiles to ensure that StressCheck’s load case has been properly interpreted and manipulated.
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Menu Option
Input Tip/Guideline
String
These two menu commands should be considered a pair. String Sections provides an up-to-
Sections,
Connections
date tabular listing of the weight/grade combinations currently comprising the casing string under focus. A blank table indicates no design has been performed. Once an entry(s) appears on the String Sections spreadsheet, that entry may be manually manipulated to change the depth range and/or weight/grade characteristics of the string under focus. The Connections spreadsheet is a companion to the String Sections spreadsheet, and provides an editable listing of the connection(s) currently attached to the pipe body entry(s) listed under String Sections.
Pipe
Inventory,
These two menu items should be considered a pair. The Pipe Inventory spreadsheet pro-
Connec-
vides a list of all weight/grade combinations available for consideration in the current design.
Special
tions Inventory
This spreadsheet is initially populated by the template chosen when the file was first created. (Choosing the BP template populates this spreadsheet with the standard BP inventory.) Once populated, however, the spreadsheet can be edited at the user’s discretion. Each StressCheck file has a separate pipe inventory attached. Altering the pipe inventory in one StressCheck file has no effect on the pipe inventory of other either existing or future StressCheck files. The Special Connections spreadsheet (more appropriately, the Connection Inventory spreadsheet) is a companion to the Pipe Inventory spreadsheet and provides an editable listing of the connection(s) currently available for associating with a tube body. To be associated with a tube body, a connection must have the same outside diameter, weight and grade.
Tubular Properties
The BP template uses the constants for temperature degradation recommended in Section 11.7 of this manual. StressCheck only adjusts the yield strength for temperature. Other factors, such as Young’s modulus, Poisson’s ratio and the coefficient of thermal expansion, are not adjusted. Whether this simplified treatment results in over-conservatism or underconservatism is problem dependent. This issue is invariably ignored in casing and tubing design.
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Figure 6.5. StressCheck View Menu and Commands
6.3.2.3.5
View Table 6.5. Input Tips and Guidelines for the StressCheck View Menu
Menu Option
Input Tip/Guideline
Tabular Results
It is not currently possible to move all StressCheck information easily to other software. Copying and pasting the MMS report, for example, to a word processor will not preserve the look of the form.
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Figure 6.6. StressCheck Tools Menu and Commands
Figure 6.7. StressCheck Window Menu and Commands
6.3.2.3.6
Tools Table 6.6. Input Tips and Guidelines for the StressCheck Tools Menu
Menu Option
Input Tip/Guideline
Preferences
Plot fonts, curves, legends, markers and grids can be customized under this command.
Reports
You can build a custom report displaying only the information you wish summarized. In the current version of StressCheck, a report cannot be written to file and then mailed electronically to a co-worker. Reports can only be printed.
6.3.2.3.7
Window
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All of the commands under Window are standard Microsoft Windows features.
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Figure 6.8. StressCheck Help Menu and Commands
6.3.2.3.8
Help Table 6.7. Input Tips and Guidelines for the StressCheck Help Menu
Menu Option
Input Tip/Guideline
Contents
The help system for StressCheck is detailed and should provide answers to most questions.
About
Stress-
This dialog window will contain the version of StressCheck with which you are working.
Check
6.3.2.4
Design Assumptions
Section B sets forth design assumptions for standard BP wells. These assumptions can be accommodated by StressCheck. If more than one load case is selected, StressCheck will base its design on a composite load that represents the maximum differential pressure at each depth. This load is further adjusted for design factor and, when appropriate, combined stress effects. • Temperature Profile. StressCheck’s load cases have built in assumptions regarding the variation of temperature for post-initial load cases. Should a reliable estimate of the actual temperature profile for a design load case exist, or should a temperature simulation be performed, that information should supersede the more extreme values assumed by the software. – Production Load Cases. For production load cases, the temperature profile is constant and equal to either the undisturbed temperature at perforation depth (production) or the undisturbed surface ambient temperature (injection). – Drilling Load Cases. For drilling load cases, the temperature profile is a straight line defined by two points: ∗ The calculated API circulating temperature ∗ The mid-point of the undisturbed temperature profile • Matching StressCheck Load Cases to Recommended Design Load Cases for Standard Wells. The BP template defaults to the load cases recommended in Section B of this manual, other than the use of static temperature for some collapse loads. EPT Drilling
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• Special Note. Before performing a Minimum Cost design, the Design tab under Tubular/Minimum Cost should always be edited to duplicate Figure 6.9. This alteration should be correct if the BP template is used to initiate the StressCheck analysis. Table 6.8. Production Load Cases for BP Template in StressCheck Loading Collapse
Load Cases Above/Below Packer Cementinga
Burst
Tubing Leak Pressure Testb Green Cement Pressure Testb
a b
Uses undisturbed temperature profile (e.g., no temperature change).
Uses API circulating temperature profile.
Table 6.9. Drilling Load Cases for BP Template in StressCheck Loading Collapse
Load Cases Lost Returns with Mud Drop Cementinga
Burst
Frac @Shoe w/Gas Gradient Above Pressure Testb Green Cement Pressure Testb
a b
Uses undisturbed temperature profile (e.g., no temperature change).
Uses API circulating temperature profile.
6.3.3
WellCat
BP uses Wellcat for the majority of tubing stress analysis and special topics in casing design. Although the program is powerful and comprehensive, there are a number of areas for confusion, and problems do arise. This section is intended to supplement the software’s help file with general pointers about stress analysis within Wellcat. 6.3.3.1
Structure of WellCat
Wellcat is comprised of five components, all of which are linked and use common well architecture input. Wellcat consists of two load generation programs (Drill and Prod) and two stress analysis programs (Tube EPT Drilling
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Figure 6.9. Recommended StressCheck Design Ellipse
Figure 6.10. Wellcat Drill and Prod Menu Structure
and Casing). For the purposes of tubing design, the programs Tube and Prod will be used. For casing design, Drill, Prod and Casing can either be used alone, or to provide input to StressCheck. MultiString is used to consider the interaction between tubulars, particularly wellhead movement and annular pressure build-up. The layout of each module is similar. Along the menu bar will be found the conventional File and Edit drop down menus followed by Inventories and Wellbore. The menus to the right of this will vary from Prod and Drill to Casing and Tube. EPT Drilling
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Table 6.10. Wellcat Modular Structure Loading
Load Cases
Drill
Drill load generation (tripping, drilling, cementing, running casing, circulating, etc.)
Prod
Tubing load generation (production, injection, stimulation, interventions, etc.) Casing
Analysis of single casing string
Tube
Tubing stress analysis
MultiString
Requires input from the four main modules to analyze complex trapped annuli effects and total wellhead movement
The layout of the menus is logical. Construct a design by working from left to right and top down, starting at the Inventory menu and working through the Wellbore, Loads and Results menus. Within each menu, working from top to bottom ensures input of all necessary data. It is possible to define the wellbore (tubing, casing, etc.) within any of Wellcat’s modules. 6.3.3.1.1
Inventories An inventory is a stored set of properties intended to ease input over a variety of
Wellcat data files. Inventories can be constructed for: • Fluids (stimulation, annulus, production fluids, etc.) • Pipes (every single combination of size, weight and grade) • Drill string • Insulators (or conductors) • Coiled tubing • Grade properties (metallurgical properties such as Poisson’s ratio) • Drill pipe grade • Temperature duration • Connections (with a new entry for every combination of size, weight, grade and connection) • Bit sizes EPT Drilling
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Figure 6.11. Wellcat Inventories Menu and Commands
• Formation properties • Cement properties. Individual inventories are not necessarily used in all parts of Wellcat but are available from every part of Wellcat. Table 6.11. Input Tips and Guidelines for the Wellcat Inventories Menu Menu Option
Input Tip/Guideline
Fluids. . .
Not all fluid inventory entries are available for all purposes. For example, hydrocarbons are not available as annulus contents. This limitation is unfortunate, as many loads cases could have their temperature affected by the presence of natural gas in the annulus. WellCat Fluid
Features
Where Used
Cement Slurries
Used for cementing operations within Drill or Prod
Brines
Expansion (e.g., as used for trapped
For use as completion fluids, stimula-
annuli calculations).
tion or other treatment fluids.
Can be either
input by table or default correlation.
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Menu Option
Input Tip/Guideline
Compositional
Includes
basic
characteristics
of
This fluid type is used in Drill (drilling)
Muds
oil/water mud mixtures.
The mix-
operations and Prod circulation oper-
tures can contain high-density and/or
ations. It is also made available for
low-density solids (low density solids
placement above cement outside cas-
are not user definable but contain
ing strings.
defaults based on fine drill cuttings). The high density solids are selectable from common weighting agents such as Barite and Hematite. The water base is selectable from previously defined brines. The only oil base is diesel. Standard Muds
Standard carbons
Hydro-
A simplistic approach to muds with
This fluid type is also used in Drill
density, viscosity and yield point defin-
(drilling) operations and Prod circula-
able, as well as base fluid type. The
tion operations. It is also made avail-
conductivity information for the base
able for placement above cement out-
type is based on water or diesel.
side casing strings.
This fluid type encompasses black-oil
Used for black oil, dry gas or mul-
hydrocarbons.
Gas composition or
tiphase flows where condensates are
gravity can be entered and used to
not significant. Can be used within
define the thermal properties of the
Tube or Prod load cases/operations.
gas (using the SRK thermodynamic
Available within the Tube module
model as a default).
There is no
for production, steady state injection,
ability to tune the PVT properties to
pressure tests, shut-in conditions and
decrease any errors; therefore, Well-
related load cases.
Cat cannot be recommended for well
methane are available as annular or
performance prediction.
completion fluids.
Nitrogen and
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Menu Option
Input Tip/Guideline VLE Hydrocarbons
Vapor-Liquid Equilibrium is a com-
Used for condensate flows.
Can
positional fluid model based on the
be used within Tube or Prod load
Peng-Robinson equation of state.
cases/operations.
Like many EoS models, this method
Tube for production, steady state
is good at predicting phase conver-
injection, pressure tests, shut-in con-
sions and is therefore useful for con-
ditions and related load cases. Nitro-
densates.
There are no interaction
gen and methane are available as
coefficients. Inherent uncertainties in
annular or completion fluids. These
these methods makes density predic-
models tend to be more accurate
tions poor.
at predicting Joule Thompson cool-
Available within
ing/heating effects. File-Defined
This is the most accurate method of
As per VLE and black-oil hydrocar-
Hydrocarbons
representing hydrocarbons containing
bons.
liquids and gas.
All relevant data
(GOR, density, heat capacity, etc.) can be imported. Linear interpolation is used between the entered pressure and temperature points; therefore a sufficient range of pressures and temperatures is required for complete and accurate coverage. Water has to be included within the liquid and not separately. Use this tab to employ data supplied from other PVT packages.
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Menu Option
Input Tip/Guideline Polymers
Polymer fluids are water-based fluids.
Available as an annulus or completion
A power law model is used to calcu-
fluid and for most load cases. Particu-
late viscosity of non-reacting polymers
larly useful within Prod as an injection
(treating fluids). With treating flu-
fluid, and can be used with sequential
ids, you must specify both N’ and K’.
operations to fully define a polymer
Since viscosity changes with tempera-
treatment.
ture, you must also specify a reference temperature for the measurements. For reacting polymers, the polymer fluid combines the program’s standard power law rheology with a model for increase of viscosity due to chemical reactions. Further details of the reacting polymer input is provided within WellCat. Foams
The program models foam where a
Available as an annulus or completion
gas is mixed with a water-base fluid
fluid and for most load cases. Again,
containing a foaming surfactant. The
easiest to use within Prod as part of a
gases available are dry or water-
full intervention sequence (e.g., coiled
saturated air, dry nitrogen, carbon
tubing foam lift).
dioxide, dry or water-saturated nitrogen, methane, and water vapor.
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Menu Option
Input Tip/Guideline
Pipes
A complete range of pipes (casing or tubing) can be added to WellCat. The pipe crosssectional dimensions can be used to calculate pipe ratings in burst, collapse and axial loads, or this information can be entered directly. The input information is self explanatory, with some exceptions:
• The rows highlighted are the ones being used by the casing and tubing configuration. • No two rows can have the same size, weight and grade. If this occurs, delete any additional rows.
• Designating Type as “special” allows performance properties to be entered manually. Designating Type as “standard” allows these properties to be calculated. Pipe properties listed on the spreadsheet are for the pipe body and not the connection.
• Critical dimensions are important for the calculation of derated pipe strength. The critical dimension is the tolerance by which the specified dimension (wall thickness, for example) is reduced. Most pipe provided has the standard API wall thickness tolerance of 12.5%. This primarily affects the burst rating, and therefore the default settings within WellCat are correct. Some pipes (such as most high alloy metals) that BP uses are, however, rated to higher specifications and have a tolerance of only 10% (or less). In these cases, the burst critical dimension should be 90.
• The entire row should be filled out in order to be used. • Save the inventory data on a regular basis. A number of stability problems have been observed when trying to enter data–particularly if data is not entered exactly as required.
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Menu Option
Input Tip/Guideline
Grade Properties
The default WellCat inventory has material properties for different grades limited in scope to standard carbon steel. When additional entries are required, it is important that the cost factor is entered (even though this field is not used). Failure to enter all the fields for the grade will render that grade unavailable. The UTS (ultimate tensile strength) value is not used for pipe or connection strength, and therefore any value greater than the yield can be used (Exception: The formulas for tensile capacity of API connections are, in general, functions of ultimate tensile strength, and should be treated accordingly.). The impact of the properties defined is considerable:
• Young’s Modulus affects any stretch calculations and will therefore affect virtually all stress calculations. Significant variations in Young’s modulus for steel (more than 2-3%) are rare.
• Poisson’s ratio effects the ballooning length change. • Thermal expansion coefficient varies significantly and tends to increase with alloy content. A high alloy metal may exhibit 30% greater thermal expansion than a carbon steel.
• Anisotropy is rare in pipe grades, but can be found in some cold worked materials such as duplex. The value is manufacturer specific.
Temperature Der-
Most pipe will reduce in strength when heated. This effect can be entered as a deration factor
ation
for a given temperature. A straight line is interpolated between temperature points. The value is usually manufacturer dependent. Temperature deration should be defined (and used) for all tubing and casing string stress calculations.
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Menu Option
Input Tip/Guideline
Proprietary
The Proprietary Connections Inventory can be used to enter basic information about connec-
Con-
nections
tions. The spreadsheet does not currently allow a full connection envelope to be defined but is useful nonetheless. Prior to entering information in this form, the pipe, grade and material properties should have been correctly entered. The Proprietary Connections Inventory spreadsheet assumes that collapse resistance is unaffected by the connection and only the burst, compression and tensile ratings may be lower than the pipe body. Having defined the tubing information (outside diameter, weight and grade), this information is used to allow the connection to be available whenever the outside diameter, weight and grade is entered in the Tubing and Casing configuration. The OD and ID of the connection are solely used for clearance checks. The burst, tensile and compressive ratings will be specific to the pipe connection and pipe body. Only one value of each can be entered, and therefore the connection envelope is essentially a rectangle. To compensate for this oversimplification of connection resistance, the worst case can be entered and any loads that are excessive can be plotted on a true connection performance envelope.
Formation Proper-
Unless accurate thermal calculations are required (e.g., for calculation of temperatures in
ties
critical casing strings or annuli), the formation does not have to be included in a tubing stress analysis model. The default formation used is an impermeable shale and therefore tends to be the least conductive. Wellhead flowing temperatures using the default will therefore tend to be pessimistic. Formations such as salt will have the largest effect (highly conductive).
Cement Properties
Cement properties are only required if accurate annuli or casing temperatures are required.
Bit Sizes
The default is a standard list of conventional hole sizes.
Drill String Grade
The drill string inventory contains a useful starting point for drill pipe, heavy weight drill
Properties
pipe and collars. The stored information is OD, ID, weight and grade. If the grade data is not available, it can be added, but stresses on the drill pipe itself are not calculated in WellCat. Therefore, only the OD, weight and ID are vital (for pressure drop and temperature calculations).
Coiled Tubing
The coil is used purely as a conduit for fluids. No coil load calculations are performed within WellCat. The basic information of OD, wall thickness and weight is entered and used for pressure and temperature predictions–primarily within the Prod module.
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Figure 6.12. Wellcat Wellbore Menu and Commands
6.3.3.1.2
Wellbore Table 6.12. Input Tips and Guidelines for the Wellcat Wellbore Menu
Menu Option
Input Tip/Guideline
Wellpath Editor
Deviation influences the trajectory of the well. Doglegs (wellbore curvature) introduce a significant axial load on tubing or casing and should be modeled either in a detailed or conservative manner. Where a well exists, the dogleg data can be entered either in the Max DLS field of the wellpath editor or using the dogleg override command. Entering data in the MD TVD and Inc. fields will specify the trajectory but not the dogleg severity. If a simplified approach is taken to trajectory input, it is easiest to use the dogleg severity override section and ensure that for any depth range the entered value is at least equal to or greater than any dogleg in the survey. Likewise, for a new well under planning it is possible to enter the planned doglegs with due allowance (e.g., +2˚ ) for actual drilling results.
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Menu Option
Input Tip/Guideline
Dogleg
This useful form allows the critical dogleg severity information to be entered independent of
Severity
Overrides
the survey. By visually scanning a survey for intervals of severe curvature, the wellbore can then be split into depth ranges with the maximum dogleg severity anticipated in each interval. The dogleg severity is especially important close to the base of the tubing or at top, where it will add to existing compressive or tensile axial loads. At the base of the tubing compressive forces may be also exacerbated by connection compressive weakness.
Casing and Tubing
Each string should have its own entry on the upper section of the frame. A combination
Configuration
string (e.g., two different weights or sizes of casing/tubing) should have one entry in the upper frame and two in the lower frame. Each entry in the lower frame should include full details including the connection. This information will be found in the inventories section and can be modified either through the inventories section or indirectly through this screen. If connection information is not entered, the program will assume that the connection is as strong as the tubing and the connection will be ignored. If connection data are not entered then any connection design factors entered will also be ignored. Glass Reinforced Plastic (GRP) lined tubing uses conventional carbon steel tubing with a grouted liner of glass reinforced plastic. Unlike conventional plastic coatings, e.g., Epoxy Phenolic, where the coating is microns thick and can be ignored for stress calculations, the GRP liner may be quite thick and has weight. GRP lined tubing can be added to the inventory. The strength of the tubing is not affected by the GRP liner; however, the weight of the tubing is affected. Therefore the mechanical properties of the tubing should be extracted from the base tubing with only the weight increased. Care is in order with connections for GRP tubing. It is common that the connections have reduced strengths due to the space required for the GRP collar. WellCat can not handle the stresses on vacuum insulated tubing.
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Menu Option
Input Tip/Guideline
Packers. . .
For many standard completion methods the entries to the packer windows should be as follows:
• A hydraulic set packer and no expansion device. This configuration should be modeled as a packer, run on production tubing, set hydraulically and without a seal bore present. If a seal bore is present then in versions of WellCat prior to 2000.1 (SP1), the additional tension that the hydraulic set packer introduces is ignored.
• A hydraulic set packer with expansion device. This configuration should be modeled as a packer, run on production tubing, set hydraulically and with a tailpipe seal assembly seal bore present. As such in versions 200.1 (SP1) and later, the model will correctly space out the expansion device taking into account the effects of a hydraulic set packer.
• A stab through packer. This type of packer is frequently used in DST operations or tubing conveyed perforating. The tubing is continuous through the packer and seals off inside the packer. This should be modeled as a mechanical packer, with a stroke through seal bore present. The packer is assumed to represent both the packer and a PBR (or other sealing device). The PBR is therefore modeled as being at the packer depth. If this assumption is not correct, then the packer depth entered should be the PBR depth. Some workarounds will then be required to get the actual movements and the loads on the tubing between the packer and the PBR, but at least the tubing above the PBR will be more accurately modeled. The slack-off section is used to allow for situations where the packer is set first with the hanger positioned above (or in rare cases below) its landing position. The slack-off can be entered in WellCat (usually by trial and error). The total movement in the initial conditions results will provide the equivalent stick-up (distance the hanger is moved after the packer has been set). The slack-off/pick-up is also very useful for modeling overpulls and any other change in loads after the packer has been set. For example, a non-intervention set packer (NIS) or hydrostatic packer is set by hydrostatic pressure alone without a plug. This can be modeled by entering a slack-of force equivalent to combination of ballooning, reverse ballooning and change in buoyancy according to the formula Fso = (1 − 2 ν)pset (Ao − Ai ). Buckling tions
Restric-
In some instances, the completion can be designed to constrain buckling. This is usually achieved by centralizers. In WellCat the capability for constraining buckling is not sophisticated. In fact, the only entry possible is a virtual ID of the casing in order to constrain the OD of the tubing. The ID of the restriction can be any length and any number can be entered. No allowance is made for a true investigation of buckling between centralizers–in terms of rotation at the centralizer, centralizer spacing, or helical vs. sinusoidal buckling. If more detail is required in modeling the buckling effect with centralizers (or connections) then tools such as finite element analysis (FEA) must be used.
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Figure 6.13. Wellcat Loads Menu and Commands
Menu Option
Input Tip/Guideline
Liner
Liner isolation packers can be entered through any of the WellCat products. The OD, weight,
Isolation
Packers
and grade for the pipe define the casing used from the top of the liner up to the packer depth. The average setting temperature and the annulus fluid define the initial state of the packer. The grade and yield data (for the defined pipe) and average temperature are only used in stress and annulus expansion calculations, and therefore are only required in the Casing and MultiString products. The liner isolation packer is assumed to be landed with no downward force in a polished bore receptacle with an ID equal to the OD of the top liner section. It is assumed that downward movement of the liner isolation packer is not allowed due to a load shoulder during stress calculations. If annulus expansion calculations are performed, the annulus behind the liner isolation packer is assumed to be sealed at both the liner isolation packer and the top of the liner.
6.3.3.1.3
Loads
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Table 6.13. Input Tips and Guidelines for the Wellcat Loads Menu Menu Option
Input Tip/Guideline
Design Parameters
WellCat has the capability of checking whether safety factors are within design factors. Design factors can be entered for the normal burst, collapse, axial and triaxial conditions as well as for connections. If connection design factors are entered, they will only be used if connections are explicitly entered. The Analysis Options Tab offers the capability of enabling temperature deration, friction or trapped annuli. Temperature deration should normally be enabled (The WellCat default is disabled–simply entering a grade of pipe that has temperature deration does not automatically enable temperature deration.) The friction calculation should not be used. Trapped annuli can be analyzed in a simplistic manner within the Casing or Tube module. The inner tubing of the annuli will reverse balloon with the change in pressures. The outer tubing of the annuli can be left rigid or allowed to balloon, with the assumption of no change in pressure on the outside of this pipe. The fluid expansion properties for the fluid in the annulus are normally default values for the fluid selected. It is possible to change the default values for the fluid by entering a PVT expansion table derived from experimental studies. This is performed in the fluid section of the inventory. If a more rigorous analysis of trapped annuli is required, the MultiString module is required.
Loads. . .
A large variety of pre-defined load cases are available within WellCat. Some can be accessed directly through Tube, while others require a previous Prod simulation. The Tube relevant load cases are as follows: Load Case
Definition
Prod
Linking a WT-Prod load case
Steady state pro-
A simplified production load case, with usually conservative predictions for
duction
pressure and temperature. No ability for gas lifted production or transient effects. The model used is based on Hagedorn and Brown. For more detail and options, use the Prod program.
Transient injection
Injection of any fluid for a length of time
Steady-state injec-
Steady-state injection
tion
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Menu Option
Input Tip/Guideline Shut-in
Extracts the temperature from a previous load case (e.g., production). The surface pressure is input and the tubing pressure gradient either extracted from a previous load case, entered directly or entered as a fluid. A long term shut-in option resets the temperature back to geothermal.
Tubing Evacuation
Full evacuation (to air) of the entire string. Optional temperature data can be extracted from a previous load case (e.g., production load case).
Tubing Leak
Uses a previous load case for tubing pressure and temperature. The annulus pressure is then reset to equal the tubing pressure.
Frac screen out
Takes a previous load case (e.g., transient injection) and extracts the temperature and tubing fluid density. The surface tubing pressure is entered directly and applied on top of the static tubing fluid. This load case is also relevant to load cases involving deadheading of any injection pump e.g., water injection.
Pressure test
Pressure can be applied to tubing or annulus with the option of a plug in the tubing at any depth. Note that tubing pressure is entered as a surface pressure, whereas annulus is entered at the wellhead depth.
Overpull
Simply applies an overpull to the tubing. This load case is worst when tubing to casing friction is included.
Custom
Any combination of pressure and temperature can be entered with the option of a single “plug” or barrier in the tubing. Additional plugs (e.g., the inflow test of a safety valve with pressure held on a tailpipe plug) can be entered by modifying the well data to give a small section of tubing with a zero diameter.
6.3.4
CWear
The CWear series of casing wear models, written by Maurer Engineering as part of DEA-42, is currently the only generally available wear predictor. CWear predictions have been shown usually to be qualitatively (location) accurate, detecting wear “hot spots” when they exist. Quantitatively, the predictive capability of CWear, when compared to field measurements, has proven to be mixed. Much of the input to CWear is straightforward. CWear does, however, contain a number of options to customize a wear analysis. The following recommendations should be followed unless local experience suggests otherwise. EPT Drilling
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The currently active version of CWear within BP is CWear 6.2. Maurer Engineering has released additional versions of CWear since the termination of DEA-42, but BP has not chosen to upgrade.
6.3.4.1
Tortuosity (Survey Tab)
Tortuosity applies a sinusoidal variation to both inclination and azimuth. Only the smooth, artificial surveys used during well planning should have tortuosity applied. The following recommendations are taken from the CWear user’s manual: • The period of the sine wave should be at least five times the average interval between adjacent survey stations. • Due to the behavior of the sine function, and if the survey stations are equally spaced from the surface, a period equal to twice the survey interval will result in no tortuosity. The period value should, therefore, be a number that will not result in frequent intersections with survey station locations. For example, if the survey stations are spaced every 100 ft., a good choice for period might be 543 ft.–at least five times the survey spacing, and a number not likely to often fall on a survey station depth. • The amplitude should be set to a value between 0.4 and 1.0 to model typical field conditions. These guidelines should be considered in the absence of field measurements. Whenever possible, the amplitude and period of the tortured curve should be calibrated with field data, as the normal force, and, therefore, wear, is sensitive to these parameters.
6.3.4.2
Dogleg Insertion (Survey Data)
Dogleg insertion shifts the survey on either side of the point of interest and then uses a new survey station to connect the shifted survey with its original path. Dogleg insertion is an important option for emulating the casing curvature in a vertical well associated with helical buckling (see Section 12.3.).
6.3.4.3
Drill Pipe Protector Calculation (Drill String Tab)
Several of the entries on the Drill String Tab are directly applicable to the calculation of the number of drill pipe protectors necessary to avoid excessive casing wear. Should drill pipe protectors be necessary, the number of protectors per tool joint is calculated from the formula: Protectors per Joint = Normal Force per TJ / Maximum Lateral Load per DP Protector,
(6.1)
where the value calculated is rounded down to the nearest integer. The normal force per tool joint is determined by assuming all the normal force on a drill pipe joint is supported at the tool joint. If the drill pipe joint length and tool joint lengths are not known, recommended values are 30 ft. and 14 in. respectively. EPT Drilling
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Table 6.14. Input Tips and Guidelines for CWear Drill Pipe Protectors Input Variable
Use in CWear
Max Lateral Load per Tool Joint
This is the maximum normal force to be tolerated on a tool joint before protectors are considered. If the normal force on a tool joint is less than this quantity, no drill pipe protectors are assumed necessary, regardless of the contact time and ensuing wear. If unknown, a recommended value is 2000 lb.
Max Lateral Load per Drill Pipe Protector
The maximum normal force each drill pipe protector can support.
6.3.4.4
Revised Burst and Collapse Resistance (Parameter Data)
Several options for displaying the effect of wear on collapse and burst resistance are available. Results from the option selected are displayed in the output windows following a wear calculation. Ignore all CWear estimates of collapse of worn casing. For the groove-type wear modeled by CWear, the reduction in collapse resistance due to wear is directly proportional to the reduction in wall thickness. When viewing the output, wear percent can be used to determine the reduction in collapse resistance.
6.4
Wear and Casing Design Software
Wear constitutes a direct threat to the integrity of affected casing when that casing is subjected to subsequent differential pressure and/or axial loads. Usually the pressure and axial loads associated with the drilling that produces wear are insufficient to cause failure. It is later loads, associated with well control or completion and production operations, when coupled with the reduced wall thickness, that pose the greatest potential for failure. • Wear is most common in extended reach and horizontal wells where either the length of rotation or the magnitude of the normal force at a point in the wellbore becomes critical. Vertical wellbores, typical of onshore and exploratory holes, are not, however, without the potential for wear. Here the culprit is usually buckling which produces a curvature in the casing corresponding to the helical trajectory of the unstable tubular. Common causes of buckling in vertical wellbores include such actions as setting a string on bottom or slacking off during WOC prior to allowing the cement time to build sufficient gel strength to support the casing. (Refer also to Section 9.1.) • Change in axial force and effective tension associated with increases in drilling fluid density and circulating temperature during drill ahead. This source has become prominent in intermediate casing strings as cement tops are lowered (below the previous shoe) to (a) avoid a trapped annulus in high pressure, high temperature (HPHT) wells and/or (b) permit annular cuttings injection. EPT Drilling
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Currently, no software contains integrated prediction of both wear and its effect on exposed tubulars. Working this problem usually involves coordinating two models–a wear model and a casing design model. The sections below offer guidance on coordinating the casing design/wear prediction procedure for both directional and vertical wellbores.
6.4.1
Wear in Directional Wellbores
In a directional wellbore, the procedure for determining the effect of wear on the integrity of a casing string is iterative: 1. Design a trial casing string (StressCheck) assuming no wear. The string should be sufficient to withstand all anticipated service loads. 2. Use the trial casing string as input in CWear and determine the wear for anticipated drilling conditions. 3. With a wear prediction in hand, check the integrity of the trial casing string. If necessary, repeat the procedure with a revised casing string. This integrity check can be made in intermediate software such as Microsoft Excel. On a common chart, data on allowable wear (View/Tabular Results/Max Allowable Wear command in StressCheck) and predicted wear (CWear) can be compared to determine if the latter exceeds the formed at any depth. Typically, only one iteration will be necessary as wear is relatively insensitive to the wall thickness and grade of casing.
6.4.2
Wear in Vertical Wellbores
The procedure for determining the effect of wear on the integrity of a casing string in a vertical wellbore is identical to the procedure for a directional wellbore with one exception. In a directional wellbore the normal force immediately follows from the inclination and directional changes of the borehole trajectory. In a vertical wellbore, however, significant wear can occur in the presence of buckling, and without buckling there is no normal force. It therefore becomes necessary to fabricate a borehole trajectory representing the helically buckled tube. The procedure to do this is as follows: 1. Design a trial casing string (StressCheck) assuming no wear. The string should be sufficient to withstand all anticipated load cases. Include a drill ahead load case, not to check for string structural integrity but rather to check for the possibility of helical buckling during drilling operations inside the trial string. 2. If buckling is predicted, compute the dogleg severity in the helically buckled tubular using the procedure described in Section 9.3. 3. Use the trial casing string as input in CWear and determine the wear for anticipated drilling conditions, using a user-specified DLS in CWear. 4. With a wear prediction in hand, check the integrity of the trial casing string. If necessary, repeat the procedure with a revised casing string. This integrity check can be made in intermediate software EPT Drilling
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such as Microsoft Excel. On a common chart, data on allowable wear (View/Tabular Results/Max Allowable Wear command in StressCheck) and predicted wear (CWear) can be compared to determine if the latter exceeds the formed at any depth.
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Chapter 7
Casing Setting Depth Guidelines 7.1
Introduction
Casing setting depth guidelines vary across BP’s worldwide operations due to the variety of geological formations, pressure regimes and asset experience. The objective of casing seat selection is to achieve the total depth of the well safely, with the most cost effective number of casings and liners. This chapter provides general casing setting depth guidelines for use worldwide, which can be supplemented by guidelines for specific operating areas.
7.2
Why Casing?
If all subsurface rock formations were comprised of competent, leak-proof material, casing the wellbore would be unnecessary. Casing is necessary, however, and is inserted in a wellbore because of certain structural inadequacies of rock.
7.2.1
Rock is Permeable
The fact that rock accommodates interstitial fluid flow, and therefore, exchange of fluids between the wellbore and surrounding formations, has several consequences: • Fluid loss or gain at the wellbore wall suggests mixing between high and low pressure formations, and between hydrocarbon and non-hydrocarbon bearing rock, both of which can be undesirable. • The influx of relatively high pressure fluids into the wellbore, termed a kick, can lead to well control events that endanger surface personnel and equipment. • Rock permeability promotes the formation of a mud cake at the wall of the wellbore, leading to the phenomenon of differential sticking1 . 1 Differential
sticking occurs when a tubular (casing, drill pipe) is motionless and in contact with a drilling fluid filter cake. The majority of the tube circumference is exposed to wellbore fluid pressure, while the portion of the circumference in contact
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7.2.2
Rock is Weak
Despite the damage that can be dealt metal structures, including wellbore tubulars, by formation movement, compared to steel rock is weak2 . This is particularly true in load conditions that place rock in tension. Insufficient wellbore pressure can result in spalling, sloughing and caving of the wellbore. Excess wellbore pressure can result in spalling of the wellbore or, more typically, fracture at the wellbore wall and loss of potentially expensive drilling fluid.
7.2.3
Rock is Chemically Active
Chemical stability addresses the transport of water from the wellbore into the formation and subsequent rock-fluid interaction. Water is generally accepted to move into the formation by several mechanisms. The result may be observed as an increase in pore pressure and a decrease in the cohesive strength of the rock due to a softening of the rock matrix [26, 23, 12]. Either or both effects can cause a decrease in the stability of the wellbore. Chemical mechanisms must be coupled with mechanical response to completely determine wellbore stability [59]. The degree of strength decrease accompanying fluid invasion will depend on the type of formation. Sandstones and carbonates, for example, with cementation provided by authigenic overgrowth formed from minerals in solution after original deposition, will show a minimum effect from water. Shales or other materials where cementation is provided largely by a clay matrix can exhibit a large effect. The variety and relative water sensitivity of clays comprising the class of rocks denoted “shale” are beyond the scope of this discussion. Suffice it to say that isolating such formations with casing, which is for all practical purposes inert to water, eliminates wellbore stability concerns related to chemical stability.
7.3
General Casing Setting Depth Guidelines
The initial selection of casing setting depths is based on anticipated pore pressure and fracture gradients. As far as possible, relevant offset data should be considered in the estimation of pore pressure and fracture gradients. Further, the effect of hole inclination on offset fracture gradient data should be addressed. The total depth of the well, and hence the setting depth of the production casing or liner, is driven by logging, testing, and completion requirements. The production casing shoe must be set deep enough to give an adequate sump for logging, perforating, and test on production activities. Figure 7.1 depicts a graphical method of generating an initial estimate of casing setting depths. The procedure is as follows: 1. Draw the mean pore pressure gradient curve along with lithology, if available. Note any intervals which are potential problem areas such as differential sticking, lost circulation or high pressure gas zones. with the filter cake is isolated from wellbore fluid pressure and exposed to formation pore pressure or less. The net fluid force on the tube cross section is directed toward the boundary of the wellbore, creating an imbalance that causes the tube to “stick” to the wellbore wall. 2 The
damage inflicted on wellbore tubulars due to formation mobility follows from the non-uniform manner in which the tubulars are loaded. See Section 8.4.2.2.
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Figure 7.1. Casing Setting Depth Diagram
2. Draw the (minimum) drilling fluid density curve. The drilling fluid density curve should include a (usually) 0.3–0.5 ppg trip margin. Specific areas may incorporate different rules for drilling fluid density trip margin (surge or other overbalance), and riser margin [3] (where applicable). 3. Draw the predicted fracture gradient curve. Draw a fracture gradient design curve, which parallels the predicted fracture gradient curve with a (usually) 0.3–0.5 ppg reduction as an approximate allowance for swab during pipe movement, well control and ECD during cementing. 4. Plot offset drilling fluid densities and LOTs to provide a check of the pore pressure predictions or highlight the need for further investigation. 5. The sequence above assumes a vertical wellbore, where the acceptable equivalent drilling fluid density range is determined by pore pressure (e.g., avoid fluid influx) and fracture gradient (e.g., avoid rock tensile failure and associated fluid efflux). An important exception to this assumption, particularly applicable to deviated wellbores, is the consideration of wellbore stability. In some instances, mechanical instability of the wellbore wall may precede pore fluid influx and further limit the acceptable equivalent drilling fluid density range. Wellbore stability should always be a consideration, but is beyond the scope of this discussion. Consult a relevant specialist. Once the equivalent drilling fluid density range has been established, to determine initial estimates of EPT Drilling
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casing setting depths: 1. Enter the equivalent mud density curve at Point A (TD). As will be clear momentarily, of the available acceptable values, between approximately 16.5 ppg (1.98 SG) and 17.8 ppg (2.13 SG), the drilling fluid density at Point A allows the greatest length of casing to be run below the next higher shoe. The lower drilling fluid density also has possible positive side effects, such as increased penetration rate while drilling. 2. Move vertically to Point B which determines the initial estimated setting depth for the intermediate casing in Figure 7.1. That is, according to the permissible equivalent drilling fluid density range established, any attempt to fill the wellbore with a drilling fluid density equal to or greater than that corresponding to Point A will fracture the formation at depths shallower than the depth corresponding to Point B. 3. Move across to Point C which identifies the drilling fluid density requirement for that depth. 4. Repeating the previous argument, move upward to Point D which determines the preferred setting depth for the previous casing in Figure 7.1. 5. Move across to Point E to identify the drilling fluid density required at that depth. For the example shown in Figure 7.1, Point E is the normal pressure range and no further casing is required to withstand the associated drilling fluid density. However, a structural and conductor casing are required. The setting depth criteria for those strings are discussed later. The method described above is the so-called “bottom-up” method of initially selecting casing seats. An alternate, “top-down” philosophy is also legitimate. In the latter alternative, one starts at the top of the fracture gradient design curve and works downward in a step-wise fashion. Here, the reasoning is that in any hole section one typically increases drilling fluid density with depth, but that increase will be limited by the fracture gradient at the uppermost depth of exposed open hole. The two methods usually result in the same number of casing seats, although the seats from the “top-down” alternative will be deeper. Other factors complicate the simple casing setting depth selection process outlined above. These include: • Well control; • Shallow gas zones; • Shallow water flow; • Lost circulation zones, which may impose upper limits on acceptable drilling fluid density; • Formation stability which is sensitive to exposure time or drilling fluid density. As mentioned above, and particularly in an inclined well, the lowest acceptable drilling fluid density to ensure wellbore stability may exceed that needed to contain formation pressures. Although wellbore stability can also alter the highest acceptable drilling fluid density, such instances are rare, and the upper range of the acceptable drilling fluid density is almost always governed by fracture of the formation; EPT Drilling
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• Directional well profile. It is important to straighten the well trajectory before setting casing and attempt to achieve a consistent survey ahead of a tangent section. Also, long, open hole sections may require casing to reduce the occurrence of stuck pipe and the level of torque; • Sidetracking requirements as specified in the FWS, e.g., 13-3/8 in. might be set high to allow 9-5/8 in. to be cut and pulled for a sidetrack with a 12-1/4 in. bit; • Fresh water sands (drinking water), may need to be isolated by surface casing to prevent contamination by wellbore fluids. There are often local regulatory requirements in this respect; • Hole cleaning, particularly if a long section of 17-1/2 in. hole is required; • Salt sections, particularly if the salt is know to be mobile; • High pressure zones; • Isolation of H2 S and CO2 bearing intervals; • Casing shoes shall, where practicable, be set in competent formations, which may require some adjustment to depth; • Uncertainty in depth estimating, e.g., establishing a margin related to confidence limit when setting casing close to a permeable formation; • Well depth, which may result in hook load limitations affecting the design–this is one possible reason for running a liner; • The presence of multiple producing intervals which may need to be isolated from each other; • The possibility of differential sticking; • Surge pressures when running casing. Once the initial casing setting depths are selected, determine the kick tolerance associated with those depths. Start from TD up to the surface to determine the kick tolerance and preferred setting depth for each casing. The kick tolerance calculation steps are provided in the BP Well Control Manual [15]. The acceptability of kick tolerance values of less than 100 bbl should be justified by a review of type of well, rig equipment for kick detection and operator/driller’s experience, area experience and geology. Some of the possible consequences of unsuccessful kick control, e.g., cratering, are considered by Walters [93]. In any case, the proposed kick tolerance for seat design should be noted for each casing, approved by the Drilling Superintendent, and recorded on the drilling program. Sensitivity studies should be conducted to identify the contingency provisions required to accommodate pore or fracture pressures during drilling which differ from those assumed during design. Kick tolerances which may be acceptable for seat selection are not an acceptable basis for mechanical burst design. EPT Drilling
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Table 7.1. Pore Pressure Gradients for Example Problem on Casing Seat Selection
7.3.1
Depth, m (ft.)
Pore Pressure Gradient, KPa/m (ppg)
914 (3,000.0)
10.22 (8.70)
3,901 (12,800.0)
10.81 (9.20)
4,023 (13,200.0)
11.16 (9.50)
4,877 (16,000.0)
11.75 (10.00)
4,968 (16,300.0)
18.21 (15.50)
5,776 (18,950.0)
18.21 (15.50)
5,913 (19,400.0)
5.29 (4.50)
6,187 (20,300.0)
5.52 (4.70)
6,248(20,500.0)
17.67 (15.04)
6,450 (21,160.0)
16.80 (14.30)
6,497 (21,314.0)
16.92 (14.40)
6,706 (22,000.0)
17.63 (15.00)
7,010 (23,000.0)
18.80 (16.00)
Example Problem
A deep, initially overpressured, mature sandstone reservoir (“A-Sand”, 5,775 to 6,220 m (18,950 to 20,400 ft.)) has been depleted by primary production. A new drilling program is being initiated to not only in-fill the current reserves but to also penetrate a deeper sand (“B-Sand”, 6,280 to 7,165 m (20,600 to 23,000 ft.)). The two sandstone formations are separated by a sealing and competent shale. Further, a limestone marker above the A-Sand is known to consistently precede this upper reservoir by approximately 6 m (20 ft.). Shallow gravel beds have consistently caused lost circulation problems. These beds are no deeper than 1,340 m (4,400 ft.). There is also a government regulation requiring all fresh water sands +500 ft. to be protected, but this provision only extends to 915 m (3,000 ft.). The pore pressure and fracture pressure are tabulated in Tables 7.1 and 7.1 and displayed graphically in Figure 7.2. Previous drilling in this area has led to the following margins: • Trip margin (swab) is 0.024 SG (0.2 ppg) • Running margin (surge) is 0.024 SG (0.2 ppg) • Safety factor (surge and swab) is 0.012 SG (0.1 ppg) • Kick margin is 0.048 SG (0.4 ppg)
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Table 7.2. Fracture Pressure Gradients for Example Problem on Casing Seat Selection
7.3.1.1
Depth, m (ft.)
Fracture Pressure Gradient, KPa/m (ppg)
914 (3000)
14.69 (12.5)
1,341 (4400)
15.86 (13.5)
3,048 (10,000)
18.21 (15.5)
4,481 (14,700)
19.98 (17.0)
4,938 (16,200)
20.56 (17.5)
6,248 (20,500)
21.15 (18.0)
6,706 (22,000)
21.74 (18.5)
7,010 (23,000)
22.33 (19.0)
Plot Upper and Lower Drilling Fluid Limits with Margins
Figure 7.2 illustrates the lower limit of drilling fluid density (based on pore pressure) and the upper fluid limit (based on fracture gradient): • For simplicity, the wellbore is taken to be vertical and no consideration is given for wellbore stability. If the wellbore is inclined, then a wellbore stability analysis is warranted. Such an analysis is likely to shift the lower bound of the acceptable drilling fluid range to the right, decreasing the acceptable range of drilling fluid densities. • The pore pressure curve indicates the effect of depleting the “A-Sand”. Depleting the “A-Sand” will also lower the fracture gradient, but the extent to which the fracture gradient is lowered may be difficult to determine in the absence of a field test. The combined margin for the lower bound of acceptable drilling fluid density (minimum drilling fluid density curve) is the sum of the trip (swab) margin and the safety margin, or 0.036 SG (0.3 ppg). The combined margin for the upper bound of acceptable drilling fluid density is the sum of the kick margin and the safety margin, or 0.060 SG (0.5 ppg). The running (surge) margin is covered by the kick margin. Adjusted design lines, including the effects of margins on the upper and lower bounds, are plotted in Figure 7.2. 7.3.1.2
Determine Initial Requirements for Wellbore Integrity
Starting at the bottom, select the lowest acceptable drilling fluid density: • Lower drilling fluid weight/wellbore pressure usually increases penetration rate; • Selecting the lowest drilling fluid density will result in the greatest distance between successive casing shoes. EPT Drilling
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0 Pore Pressure w/Margins Fracture Pressure w/Margins
2000
4000
6000
8000
Depth (ft)
10000
12000
14000
16000
18000 Limestone Marker
.. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. A ... ... ... ... ... ... ... ... ... ... ... ... ... ... ... ... .. .. .. .. .. . . . . . ........... ........... ........... ........... ........... ........... ........... ........... B ........... ........... ........... ........... ........... ...........
20000
22000
24000 0
2
4
6
8
10
12
14
16
18
20
Pressure Gradient (ppg) BPAD003_020.ai
Figure 7.2. Example Pore Pressure and Fracture Gradient Plot with Margins in Place
In this case, the initial density is 1.955 SG (16.3 ppg). Constructing a vertical line from well depth as shallow as possible, the kick margin line for fracturing the formation is intersected at approximately 4,270 m (14,000 ft.). Using 1.955 SG (16.3 ppg) drilling fluid below this depth will endanger shallower formations, EPT Drilling
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so a casing string run to 4,270 m (14,000 ft.) to isolate shallower zones is in order. Construct a horizontal line from 4,270 m (14,000 ft.) to find the lowest acceptable drilling fluid density to drill upper portions of the wellbore. Such a line intersects the lower acceptable margin at approximately 1.200 SG (10 ppg). A vertical line from 1.200 SG, 4,270 m (10 ppg, 14,000 ft.) will extend to the surface without intersecting the upper acceptable drilling fluid curve, indicating that the entire upper section of the hole can be drilled with 10 ppg mud. Ignoring all other considerations, this initial step indicates that only two casing strings are necessary; one at approximately 4,270m (14,000 ft.) and one at well depth. The upper portion of the hole could be drilled with 1.200 SG (10 ppg) drilling fluid and the lower portion of the hole could be drilled with 1.955 SG (16.3 ppg) drilling fluid. 7.3.1.3
Check for the Possibility of Differential Sticking
The check for differential sticking is the first of several tests that are applied to the initial casing points from the previous step. The objective of these tests is to adjust the “draft” casing seats to account for effects not covered by wellbore stability (not considered in this example) and fluid influx. Large excursions in the pore pressure plot are likely points to check for the possibility of differential sticking3 . One such point in the current analysis is the transition at approximately 4,880 m (16,000 ft.) to abnormal pressure. At that depth, the differential pressure under the currently proposed programme is 9.81 N/kg x (1,955 - 1,200) kg/m3 x 4,880 m = 36.1 Mpa (0.052 psi/ft/ppg x (16.3 - 10 ppg) x 16,000 ft. = 5,240 psi), which far exceeds the suggested 13.8 to 15.9 MPa (2,000 to 2,300 psi) tolerable range to avoid differential sticking4 . The implication is that the normally pressured zones above 4,880 m (16,000 ft.) must be cased off prior to increasing the drilling fluid to the densities necessary to drill the lower portion of the well. The consequences of these results are as follows: • Casing must be set at or just below 4,880 m (16,000 ft.). Here, the casing seat is set at 4,910 m (16,100 ft.); • In order to drill to 4,910 m (16,100 ft.), the drilling fluid density above this depth must be increased. The original selection of 10 ppg could result in influx of reservoir fluids below depths of 4,270 m (14,000 ft.). A similar situation exists in conjunction with the severely depleted “A-Sand”. Here we can use the limestone marker as a target casing seat, allowing the drilling fluid density to be decreased prior to drilling through this reservoir. Based on Adams and Charrier’s [5] differential sticking criterion, an acceptable upper 3 Keep in mind that the pore pressure plot has an abscissa with units of pressure gradient, whereas the differential sticking pressure check is based on pressure. An excursion on the pore pressure plot that has a relatively small difference between equivalent mud density and pore pressure gradient may still pose a risk if it is deep. 4 The
differential sticking calculation, as performed here, uses as its lower limit the pore pressure curve with margins. Whether to use the pore pressure curved itself or the adjusted curve with swab and safety margins is largely a matter of personal preference. Choice of either curve must, however, be rationalized with the differential sticking criterion. That is, one may prefer to use the pore pressure curve without margins as the lower limit in the calculation, but this will probably alter the acceptable differential pressure limit value upward.
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0 Pore Pressure w/Margins Fracture Pressure w/Margins
2000
Drilling Fluid
4000
6000
8000
Depth (ft)
10000
12000
14000
Diff Sticking?
16000
18000 Limestone Marker
.. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. A ... ... ... ... ... ... ... ... ... ... ... ... ... ... ... ... .. .. .. .. .. . . . . . ........... ........... ........... ........... ........... ........... ........... ........... B ........... ........... ........... ........... ........... ...........
20000
22000
Diff Sticking? Lost Circulation?
24000 0
2
4
6
8
10
12
14
16
18
20
Pressure Gradient (ppg) BPAD003_021.ai
Figure 7.3. Example Pore Problem following Initial Selection of Casing Seats
limit for drilling fluid density opposite the “A-Sand”, at an average gradient of 0.550 SG (4.6 ppg), is 0.790 to 0.825 SG (6.6 to 6.9 ppg). This is too low to be practical, but does alert us to the fact that sticking could still be a problem in this interval. The “B-Sand” also displays a pressure regression, but a check indicates a potential differential pressure of EPT Drilling
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Table 7.3. Final Casing Seats for Example Problem Casing Seat, m (ft.)
Purpose
Planned Fluid Density, SG (ppg)
1,340 (4,400)
Formation constitution (shallow gravel beds)
1.235 (10.3)
4,910 (16,100)
Differential sticking (normal/abnormal transition)
1.235 (10.3)
5,770 (18,930)
Differential sticking (entering
1.895 (15.8)
depleted sand) 6,250 (20,500)
Entering new sand
1.800 (15.0)
7,160 (23,500)
Well depth
1.955 (16.3)
9.81 N/kg x (1,955 - 1,750) kg/m3 x 6,450 m = 13.0 MPa (0.052 psi/ft/ppg x (16.3 - 14.6 ppg) x 21,160 ft. = 1,870 psi, which meets the 13.8 to 15.9 MPa (2,000 to 2,300 psi) tolerable range to avoid differential sticking. Incorporating the results of this step, a revised casing seat plot is presented in Figure 7.4. Casing seats are now planned at 4,910 m (16,100 ft.), 5,770 m (18,930 ft., e.g., the limestone marker), 6,250 m (20,500 ft., e.g., the competent shale separating the “A-Sand” and “B-Sand”) and at well depth. 7.3.1.4
Check Formation Constitution
Experience indicates drilling fluid losses in shallow gravel beds above 1,340 m (4,400 ft.). To avoid continuing problems between above 1,340 m (4,400 ft.) and the casing seat at 4,910 m (16,100 ft.), a surface casing string is set at 1,340 m (4,400 ft.) to isolate this trouble zone. Setting this string also honors the government regulation regarding the isolation of shallow fresh water sands. 7.3.1.5
Final Results
Table 7.3 below summarizes the casing seats for this example, with a brief reference to cause.
7.3.2
Structural Conductor Casing Setting Depths
For the structural casing and structural conductor casing with a diverter, the setting depth should provide sufficient strength to allow circulation of the heaviest anticipated drilling fluid density in the next hole section and support the loads from the wellheads, BOPs and additional casing strings (if applicable). Structural casings are drilled, driven or jetted in place based on the operating area.
7.3.3
Conductor Casing Setting Depths
For the conductor string, the shallowest setting depth is the depth at which bottom hole pressure created by the drilling fluid being circulated (ECD) during the next hole section, is equal to the fracture pressure of the formation. EPT Drilling
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0 Pore Pressure w/Margins Fracture Pressure w/Margins
2000
Drilling Fluid
4000
6000
8000
Depth (ft)
10000
12000
14000
16000
18000 Limestone Marker
.. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. A ... ... ... ... ... ... ... ... ... ... ... ... ... ... ... ... .. .. .. .. .. . . . . . ........... ........... ........... ........... ........... ........... ........... ........... B ........... ........... ........... ........... ........... ...........
20000
22000
24000 0
2
4
6
8
10
12
14
16
18
20
Pressure Gradient (ppg) BPAD003_022.ai
Figure 7.4. Example Pore Problem following Check for Differential Sticking
7.3.3.1
Effective Mud Weight
When calculating the bottom hole pressure (effective mud weight) at the conductor shoe, the density increase due to drilled cuttings in the annulus along with the annular pressure losses must be determined. Although EPT Drilling
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pressure losses in large diameter holes may be negligible, the bottom hole density can be greatly affected by high drilling rates and/or poor hole cleaning. The increase in bottom hole density due to accumulated drilled cuttings in the annulus is difficult to calculate because of the many variables that affect it, i.e., ROP, flow rate, slip velocity, hole angle, formation density, washout, etc. In practice, surface holes below the conductor pipe are often drilled with seawater (offshore) and high viscosity sweeps. The slip velocity is dependent on whether the cuttings are transported by the seawater or a sweep. The following equation calculates resulting static fluid density due to annular drilled solids build-up, assuming the slip velocity is zero, the wellbore trajectory is vertical, and no washout is occurring: 2
2 Dh [in] ×Rp
γmds [ppg] =
h
ft/hr
i
γds [SG] ×8.33
1029
2 Dh
[in]
2
×Rp 1029
h
i
ft/hr
+ Q [gal/min] × γm [ppg] × 1.43
,
(7.1a)
+ Q [gal/min] × 1.43
or in Hybrid units,
γmds [ppg] =
Dh2 [in] 2 × Rp [m/hr] γds [SG] × 3.187 × 10−3 + Q [gal/min] × γm [SG] × 3.187 × 10−3 Dh2 [in] 2 × Rp [m/hr] × 3.187 × 10−3 + Q [gal/min] × 1.43
,
(7.1b) or in SI units, 2 Dh [mm] 2 ×Rp
γmds
kg/m3 =
h
i
m/hr
γds
h
kg/m3
i
×10−6
+ Q m3 /min × γm kg/m3 , 2 [mm] 2 ×R −6 3 Dh p m/hr ×10 + Q m /min 60 60
h
i
(7.1c)
where γds ranges depending on the cuttings (sands 2.6, shales 2.4 to 2.6). 7.3.3.2
Equivalent Circulating Density (ECD)
The bottom hole density under dynamic conditions or ECD is calculated by determining the annular pressure losses and adding this value, converted to ppg or SG, to the bottom hole density under static conditions. Annular pressure losses are affected by fluid viscosity, hole length, and annular velocity. The calculation will vary depending on the type of fluid flow, i.e., turbulent vs.laminar flow. Once the annular pressure losses are determined, the bottom hole density under dynamic conditions (equivalent circulating density) can be calculated using the following equation: ∆pa [psi] , 0.052z [ft]
(7.2a)
∆pa [psi] , 1.4206z [m]
(7.2b)
γe [ppg] = γmds [ppg] + or in Hybrid units,
γe [SG] = γmds [SG] +
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or in SI units,
γe kg/m3 = γmds kg/m3 +
∆pa [MPa] , 9.80665 × 106 z [m]
(7.2c)
where ∆pa signifies annulus pressure losses and z is the true vertical depth of the conductor casing shoe. 7.3.3.3
Annular Pressure Loss
To calculate the annular pressure loss (∆pa ), the following approximation can be used. (Laminar flow) La [ft] σyp [lb/100 sq ft] µp [cp] La [ft] Ua [ft/s] + 2 2 200 (Dh − D) [in] 1000 (Dh − D) [in]
(7.3a)
La [m] σyp [lb/100 sq ft] µp [cp] La [ft] Ua [m/min] + 2 2 61 (Dh − D) [in] 5574 (Dh − D) [in]
(7.3b)
∆pa [psi] = or in Hybrid units,
∆pa [psi] = or in SI units,
∆pa [MPa] =
106 µp [cp] La [m] Ua [m/min] 0.001 ∗ La [m] σyp [MPa] + (Dh − D) [mm] (Dh − D)2 [mm] 2
(7.3c)
where here Dh refers to the inside diameter of the casing or the hole diameter, and D is the diameter of the drill pipe or drill collars. Certain estimates may have to be made, but it should be possible to obtain a reasonable figure for the ECD at the casing shoe. In most cases, the ECD has minimal impact on the effective mud weight at the casing shoe. However, in areas where lost circulation is critical, the ECD should be included in the calculations. Figure 7.5 graphically shows the minimum setting depth where the fracture gradient is equal to the effective mud density. 7.3.3.4
Hammers and Geotechnical Data
Another method frequently used to set structural casings rather than drilling is to drive the casing to depth with hammers. For reference, Table 7.4 contains information on the diesel hammers which are typically used to drive from the drill floor. A D36 or D46 hammer is most common. Recently, jackup conductors have been driven with a D46. The D30 is generally too small to achieve much penetration; the D62 is generally too big to be lifted in one piece, resulting in expensive assembly time on the drill floor. The diesel hammers that are used on the drill floor (whether for a jackup or platform rig) are generally smaller than the steam hammers available to pre-install conductors. Therefore, the penetrations that are achieved from the drill floor are often less. EPT Drilling
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Figure 7.5. Minimum Setting Depth for Structural Conductor Casing to Prevent Lost Circulation
Hydraulic hammers may be used as an alternative to diesel hammers. Hydraulic hammers have the advantage of requiring a smaller unit on the rig floor (a hydraulic power pack comes in addition) and being much quieter in operation. They exhibit different blow characteristics from diesel hammers. Geotechnical data can be obtained from various sources. For jackup wells and for shallow semi-submersible wells, atlas or offset information is generally available. For platform wells, the soils investigation required to design the platform will provide detailed information. For deep semi-submersible or drill ship wells where no offset data is available, a quick soils investigation, using drill pipe, can be taken before spudding the well. Interpretation of geotechnical data by a soils expert permits preparation of estimates of the carrying capacity of a conductor as a function of the depth at which it has been driven or jetted. Prediction of driving resistance is much more difficult. The only reliable way is to use offset data. Do not to place too much faith in analytical predictions of driving resistance, even when these are prepared by the most reputable geotechnical consultants.
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Table 7.4. Diesel Hammer Specifications (Ref. www.hammersteel.com) DELMAG Technical Data for Diesel Hammers
Diesel Pile Hammers
Piston Weight Energy Per blow Max/Min (Adjustable)
Model
D30-32
D36-32
D46-32
D62-22
lbf
6.615
7.938
10.143
14.600
ft-lbf
69.898/35.383
83.880/40.900
107.177/52.260
165.000/78.960
36/52
36/53
37/53
36/50
Blows Per Minute Min/Max Consumption Diesel Fuel
gal/hr
2.64
3.04
4.23
5.28
Lubrication Oil Capacity
gal/hr
0.26
0.61
0.61
0.84
Diesel Fuel Lubrication Oil
gal
17.70
23.51
23.51
25.86
gal
5.02
4.49
4.49
8.32
lbf
12.855/13.472
16.515/17.375
18.720/19.580
26.173/27.077
lbf
397
882
882
882
lbf
220
220
220
275
in
207.1
208.1
208.1
232.6
a Length Over Cylinder Extension b Impact Block Diameter
in
246.4
247.4
247.4
272.0
in
22.0
27.2
27.2
27.9
c Width Over Bolts d Hammer Width Overall
in
30.7
34.6
34.6
32.6
in
25.2
28.3
28.3
31.5
e Width for Guiding–Face to Face
in
21.2
25.2
25.2
22.0
f Hammer Centre to Pump Guard g Hammer Centre to Bolt Centre
in
15.9
17.9
17.9
19.3
in
9.2
10.8
10.8
15.0
h Hammer Depth Overall H Minimum Clearance for Leads
in
28.1
31.6
31.6
38.2
in
17.3
19.7
19.7
19.7
Operating Weights–Approximate Hammer Tripping Device Tool Box Dimensions a1 Length Overall
7.4
Estimation of Fracture Gradient
Where the fracture gradient is not known from offset data, an estimate must be made. A number of predictive methods are available. The following method, after Daines [28] is one technique. Daines states that the fracture pressure can be calculated for any depth if the overburden gradient, pore pressure and Poisson’s Ratio for the particular lithology are known: pf r = σte + (σob − pp )
ν + pp . 1−ν
(7.4)
where σte is assumed to be zero if no other value is available. Poisson’s ratio is taken from Table 7.5. Overburden pressure can be calculated from Figure 7.6. EPT Drilling
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To convert pp into a gradient, γf r , use one of the following equations: pf r [psi] , 0.052z [ft]
(7.5a)
pf r [psi] , 1.4206z [m]
(7.5b)
γf r [ppg] = or in Hybrid units,
γf r [SG] = or in SI units,
γf r [MPa/m] =
pf r [MPa] . z [m]
(7.5c)
The fracture pressure can be calculated for each principal formation or depth of interest and plotted.
Table 7.5. Suggested Poisson’s Ratio for Different Lithologies (From [94]) Lithology
Poisson’s Ratio
Clay, very wet Clay
0.5 0.17
Conglomerate
0.20
Dolomite
0.21
Greywacke: Coarse
0.07
Fine Medium
0.23 0.24
Limestone: Fine, Medium
0.28
Medium, Calcarenitic Porous
0.31 0.20
Stylolitic Fossiliferous
0.27 0.09
Bedded Fossils Shaley
0.17 0.17
Sandstone:
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0.05
Coarse, Cemented Fine
0.10 0.03
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Figure 7.6. Composite Overburden Stress Gradient for All Normally Compacted Continuous Depositional Basins
Very Fine Medium
0.04 0.06
Poorly Sorted, Clayey Fossiliferous
0.24 0.01
Shale: Calcereous (50% CaCO) Dolomitic
0.14 0.28
Siliceous Silty (70% Silt)
0.12 0.17
Sandy (70% Sand)
0.12
Kerogenaceous Siltsonte
0.25 0.08
Slate
0.13
Tuff: Glass
0.34
Other commonly used fracture pressure equations and correlations include: EPT Drilling
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1. The Hubbert and Willis equation [43]; 2. The Mathews and Kelly correlation [58]; 3. The Pennebaker correlation [82]; 4. The Eaton correlation [30, 31]; 5. The MacPherson and Berry correlation [53]; 6. Mario Zamora [96].
7.5
Casing Depth Selection Guide–North Sea
Section 7.3 provides general requirements for selecting casing depths in any area. This section provides specific casing depth selection guidelines for offshore UKCS.
7.5.1
Structural (Conductor) Setting Depth
In offshore exploration drilling operations, a four-length structural (conductor) casing is the norm except where: • Water depth > 1,000 m, • Soil conditions are poor, • A deeper conductor is required to prevent losses, e.g., where a pin connector is being run to mud-up. (Structural) conductor design for deep water (> 1,000 m) and/or poor soil conditions should be evaluated on a case-by-case basis. Experience in the Gulf of Mexico for deep water drilling is considered in Section 7.6. For platform drilling, if the platform has been secured to the seabed with piles, then the effect on setting depth needs to be investigated. Where possible, the conductor shoe needs to be set below the pile depth to avoid potential losses. On a platform, the structural (conductor) casing may also be “nudged” to gain well separation and reduce well collision risk. Structural conductor setting depth needs to be checked to ensure sufficient fracture strength while drilling as referenced in Section 7.3. Insufficient fracture strength can result in conductor slump and considerable lost time. Structural conductor designs for template drilling should be as near vertical as possible for tieback considerations. In cases where the conductor is cemented, cementation is critical to the conductor structural integrity. Top-up jobs should be performed where there is doubt about the top of cement following primary cementation. EPT Drilling
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7.5.2
Conductor or Surface Casing Setting Depth
Surface casing must be set deep enough to ensure sufficient resistance to leak-off to support the drilling fluid density required to drill the over-pressured Tertiary shale sections where present and provide sufficient kick tolerance. In practice, this means setting the casing at 1,000 m to obtain sufficient leak-off. Setting the casing deeper than 1,000 m is difficult, as the section is drilled riserless, and also because of the rapid increase in pore pressure below 1,000 m. Kick tolerance for the surface casing is calculated on the basis of a water kick from the intermediate shoe depth. Kick tolerance is low because of the high drilling fluid density but this is acceptable as no hydrocarbons are expected. The change from water-based muds to oil-based muds in normally takes place after setting surface casing (usually 20 in. but possibly 18-5/8 in. or 13-3/8 in. in the case of downsized wells). If reactive shales are present, the surface casing may be set at a depth to avoid hole problems drilling shales with water-based muds.
7.5.3
Casing Setting Depths for HPHT Wells
For high pressure high temperature (HPHT) wells, casing seat selection is critical. The current BP HPHT design is a five-string design based on drilling 8-1/2 in. hole through the Jurassic reservoirs with the contingency to drill 6 in. hole in the event of hole problems or increased overbalance in the reservoir. The casing seat selection criteria for the HPHT production casing (or intermediate casing for DST) is as follows: 1. At a minimum depth to ensure sufficient fracture gradient to provide adequate kick tolerance for drilling the reservoir; 2. Maximum depth of top Jurassic; 3. At a depth where the kick tolerance while drilling for the production casing reduces to a predetermined unacceptable limit. In practice, the setting depth of the production casing depends on the pressure transition zone at the base of the Cretaceous, which depends on the effectiveness of the reservoir seal. The pressure transition can either occur rapidly over a short interval (30 m) or gradually over a longer interval (300 to 500 m). The intermediate casing (13-3/8 in.) must be set sufficiently deep to ensure that a high drilling fluid density (1.80 to 1.85 SG: 15 to 15.4 ppg) can be used to allow the production casing to be set deep into the transition zone. In practice this means casing off Paleocene sands, persevering through the “dirty” Ekofisk Chalk and setting the intermediate casing in the Tor formation. To date, the gas kick profile for the intermediate casing has been calculated on the basis of a 25 barrel kick drilling into an over-pressure of 300 psi above the drilling fluid density. The Health and Safety Executive (HSE) has accepted this in a previous program although the United Kingdom Offshore Operators Association guidelines require designing for gas to surface from the leak-off at the intermediate casing shoe. This matter is unresolved. EPT Drilling
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Ideally, the production casing should be set as deep as possible into the base Cretaceous to obtain a higher leak-off because of the increasing pore pressure and case-off potential sands/fracture zones. Where the pressure transition occurs over a short interval, it is possible to set the production casing deep. However, the production casing may have to be committed high if the permeable formations are penetrated below the transition. This leaves a long 8-1/2 in. hole and increases the risk of penetrating weak formations not capable of supporting the drilling fluid density required to drill the reservoir, thus requiring the 7 in. liner to be set as a drilling liner.
7.6
Casing Depth Selection Guide - Gulf of Mexico
The guidelines in Section 7.3 provide the basic casing depth selection criteria which is used in the Gulf of Mexico. The acceptable setting depth criteria for casing strings that require a BOP (SC, IC) is to provide a safety margin of 0.5 ppg between fracture pressure (LOT) and maximum anticipated drilling fluid density. Lower margins must be approved by drilling leadership. Specific issues for driving structural casings and deep-water criteria are described in the following two sections. The two sections are separated based on water depths to identify the impact of deep water on casing setting depth selections.
7.6.1
Gulf of Mexico Operations in WD < 2,500 ft.
7.6.1.1
General
The main role of the structural conductor casing (also called drive pipe in the Gulf of Mexico) is to provide both structural support and formation integrity. In most cases it is made of 36 in. pipe. The optimum setting depth of the conductor is determined by combining particular site conditions with structural support and formation integrity criteria in a cost benefit determination. The actual conditions vary between jackup wells, semi-submersible (or drillship) wells and platform-drilled wells. 7.6.1.2
Jackup Structural Conductors
Generally the structural conductor will be 30 in. and is driven from the drill floor by means of a diesel hammer. Water depths will typically be up to 300 ft. The structural role is to provide a riser which will protect the well from the marine environment and support the BOP and whichever casing load is not carried by a mudline suspension system. If the water is deep, if the well is very deep, or if the conductor is to function in a freestanding mode once the well is drilled, then the conductor will generally be larger5. The formation integrity role is to set the pipe deep enough to drill and cement the next casing without lost circulation. Typically a 26 in. hole is drilled to set 20 in. pipe (reference Section 7.3). In this case, the conductor is typically driven to refusal. In most areas in the Gulf of Mexico, there is sufficient offset data to reasonably predict that depth. There is also a geotechnical atlas which covers most of the jackup areas in the Gulf. This geotechnical information can be used to predict load capacities for 5 BP
has used sizes up to 60 in. with a top tapering to 42 in. for a 20,000 ft. well which was to remain freestanding in 85 ft. of water with all casing hung from the top.
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conductors driven to a specified depth. Typical penetration depths vary between 200 ft. and 300 ft. However, in some areas where there are hard sand layers, less penetration may be expected. Given the typical water depths for jackups, these penetrations will generally provide enough integrity to drill, although sometimes remedial cementing may be needed. Some attention to the actual depth is recommended. On the one hand, 30 in. pipe typically costs 2-1/2 times as much as 20 in. pipe and as such there is no advantage to set it deeper than needed. On the other hand, lost circulation and remedial cementing work may be expensive. 7.6.1.3
Semi-submersible Structural Conductors
Generally the structural conductor will be 30 in. and is jetted in from the seabed. In some cases with special casing requirements or weak soils, 36 in. has been used. The structural role is to support the subsea well. This includes providing support for the 20 in. and later for the BOP stack. At the top, the 30 in. is also structurally linked to the wellhead (lockdown system) to provide support and avoid overloading the 20 in. The formation integrity role is less critical, since returns of the next hole section (typically 26 in. hole for 20 in. pipe) are taken to the seabed; but again, a minimum is desirable, especially to provide a good cement job for the next string. In this case, a length of pipe is selected which is sufficient to meet structural and lost circulation requirements and short enough to ensure that the guide base ends up close to or on the mudline. This length is typically between 150 ft. and 250 ft. In shallow water, offset data are generally available to make a reasonable estimate of what will work. In deep water, fewer or no offset data are available. The soils are typically much softer and problems have been experienced with the 30 in. sinking when the 20 in. or the stack is landed. One solution used in the past is to start the well by making a quick geotechnical check through drill pipe. The results from this check can then be used to select the appropriate length of conductor which is long enough to give support and short enough to permit jetting in the entire string. Again, minimum cost/benefit/risk considerations are required to select a particular depth. The same ratio of cost of 30 in. versus 20 in. applies. 7.6.1.4
Platform Structural Conductors
Generally the conductor will be 30 in. but sometimes other sizes are used6 . As was the case with the jackup, the structural role is to provide a riser which will protect the well from the marine environment and support the BOP and casing loads. The presence of a permanent facility and number of wells mean shallow integrity is more important as excessive damage from lost circulation problems could have dramatic consequences. In deep water, the practice of taking returns to the surface makes achieving this integrity more difficult. The sum of the overburden, plus the water column approaches the weight of a mud column, as water depth increases and becomes critical in deep water. Two cases are to be considered. The most common is where the conductors are pre-installed together with the platform. On a platform with more than a few conductors, this approach is always much more 6 For
example, both Mississippi Canyon 109 (1030 ft. water) and Vioska Knoll 989 (130 0 ft. water) are designed with 26 in. conductors.
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economical. However, because of the nature of this installation work, the final penetration depth must be set before going offshore and a drive to refusal solution is generally not practical. Detailed data on soils, if available, can be used to make good estimates of shallow formation integrity as a function of depth. The soils data, together with offset data, can also be used to predict driving resistance. Based upon the predicted driving resistance, a depth can generally be selected by comparing costs to drilling risks. In deep water, the problem of shallow integrity is helped by installing return pumps that take mud out of the conductor just above the waterline. In very deep water, gates in the conductor allow taking returns to the seabed7 . Typical setting depths have been between 300 ft. and 450 ft. below mudline. Care must be taken not to drive conductors too deep because the deeper the conductors are driven, the more they tend to deviate. Multiple conductors can gradually migrate to a common weak path and end up closer than desirable. An alternate case occurs when a conductor is driven in an empty slot from the drill floor. As with the jackup, these are typically driven to refusal. The setting depth is selected as in the other cases. If many conductors are already in place, care should be taken not to drive such a conductor into an exisitng producing well. One solution may be to drill the conductor in, with directional control (if possible).
7.6.2
Gulf of Mexico Operations in WD > 2,500 ft.
The 36 in., 1-1/2 in. wall structural casing is jetted below the mudline to a depth able to withstand axial load requirements for the BOPs and subsequent casings. For wells in a new area, a soil survey is recommended to provide setting depth guidance for the structural casing. Guidelines can be obtained for setting depths as shown in Figures 7.7 and 4.8. Installation procedures are significant in obtaining the desired structural support. Jetting the casing with a minimal amount of reciprocation provides the best frictional support. Jetting procedures in the deepwater Gulf of Mexico are as follows: 1. Spud 36 in. with pumps off and build up to 10,000 lbf weight (15 to 20 ft. penetration); 2. Kick pumps on at a low rate (60 spm) and observe any signs of breaching at the mudline; 3. Increase pump rate to 900 to 1200 gpm to jet and pump high viscosity sweeps every 100 ft. 4. Reduce pump rate to 900 gpm for the last 60 ft. to minimise wash out at the shoe; 5. Continue jetting until mud mat is resting on the sea floor. Set down the full casing weight on the mud mat/casing. Keep reciprocation of 36 in. to a minimum to maintain downward movement and avoid reciprocation over the last 60 ft. if possible. The above procedures are provided as guidelines for jetting. For the casing, use 120 ft. of Grade X80 below the 36 in. housing, then Grade X56 for the remainder of the string. The top section and connectors should be designed to withstand 2.5 million ft-lbf bending moment. The design condition is for the flex joint to be locked out at 10◦ . With the soft sediments on the sea floor, the largest mud mat that can be handled is recommended. This will help to keep sediments away from the wellhead in the event settling takes place. 7 This
was used by Shell on the Bullwinkle in 1350 ft. water depth.
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0
100
200
300
500
600
Ultimate Pile Capacity 30" Diameter Jetted Conductors API RP 2A (1989) Method Boring1, Block 160 Green Canyon Area
50
Penetration below Seafloor (Feet)
400
100
150
200 Notes: 1. Initial capacities are presented 2. End Bearing due to the mudmat included at 245-ft penetration
250
Compression without end bearing and tension upper bound Compression without end bearing and tension lower bound
300 BPAD003_032.ai
Figure 7.7. Ultimate Pile Capacity Example, Green Canyon, Gulf of Mexico
Attempt to get the 22 in. conductor8 to 2,000 ft. below the mudline to maximize leak-off gradient for the next hole section. This hole section is drilled riserless and therefore is usually site specific as to whether the hole can be kept open using the seawater system to that depth. The range usually falls between 1,200 to 2,000 ft. Very low leak-off gradients down to intermediate casing points are the norm in deepwater drilling and this dictates additional casing strings and flexibility while drilling to take advantage of higher than anticipated leak-offs. The current standard design for a well in deep water requires 36 in., 28 in. and 22 in. as noted above, followed by 18 in., 16 in., 13-5/8 in., 11-7/8 in., 9-7/8 in. (exploratory well) or 10 in. (development well), and a 7-3/4 in. or 7 in. liner. 8 There
is often a 28 in. string between the conductor and 36 in. structural casing.
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1,000
800
Tensile Load in kips
Upper Bound e of Rang
600
Capa
city
Lower Bound
400 30" Diameter Driven and Jetted Conductors Boring 1, Block 160 Green Canyon Area
200
0
0.01
0.1
1
10
100
Time in Days BPAD003_033.ai
Figure 7.8. Conductor Tension Load vs. Time
Setting depth for the 18 in. or 16 in. string is commonly based on the drilling fluid weight getting to within 0.3 ppg of the leak-off gradient. Kick tolerance is therefore usually less than 50 bbl. Despite the tight margins between drilling fluid density and leak-off gradient, loss circulation during cementation has not been a problem to date. Because of a lack of offset data, maximum use is made of seismic to predict optimum setting depths for casing shoes. For deeper casing strings and where the potential for hydrocarbons exists, setting depths are based on maintaining a “theoretical” kick tolerance above 50 bbl.
7.7
Keathley Canyon 255 No. 1 Example
For guidance, an example of the casing setting depth criteria for Keathley Canyon 255 No. 1 is provided below:
7.7.1
30 in. Structural Pipe–6,123 ft. BRT
The 30 in. will be jetted to 245 ft. below the mudline. To maximize skin friction, every effort must be made to reduce reciprocation of the pipe during the jetting operation, especially for the last couple of lengths. It is accepted that this will increase the time to jet in the 30 in. pipe. If feasible, increase the number of 9 in. collars run in the BHA to provide additional weight. EPT Drilling
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7.7.2
20 in. Surface Casing–7,880 ft. BRT
The aim is to set the 20 in. surface casing 2,000 ft. below the mudline. Deepwater drilling experience to date (BP/Shell/Exxon) suggests that this is the optimum setting depth for the surface casing string in order to achieve a realistic leak-off value. Because we are limited in this hole section to drilling with seawater and gel sweeps, the actual depth will be dictated by hole conditions and could vary anywhere between 1,200 ft. to 2,000 ft. below mudline.
7.7.3
16 in. Liner–9,850 ft. BRT
Setting depth will most likely be dictated by the leak-off test obtained at the 20 in. shoe and drilling fluid density requirements. The aim should be to drill to within 0.3 ppg of the leak-off value to a maximum of 9,850 ft. (approximately 100 ft. above a primary objective). Kick tolerance through this interval is limited to 54 bbl based on programmed drilling fluid densities and leak-off.
7.7.4
13-3/8 in. Casing–11,200 ft. BRT
Setting depth will be dictated by the leak-off obtained at the 16 in. shoe. If the leak-off is as low or lower than predicted, the actual setting depth will be based on the drilling fluid density reaching 0.3 ppg below leak-off. Kick tolerance through this interval is estimated at 79 bbl based on programmed drilling fluid densities and leak-off. Should a higher leak-off be obtained and/or drilling fluid densities required be lower than anticipated, it may be possible to extend the setting depth beyond 11,200 ft. and possibly eliminate the 11-3/4 in. liner string. In this case, setting depth will be dictated by the burst rating of the 20 in. string to a maximum of 13,100 ft. (100 ft. above a secondary objective) at which point an intermediate string of casing must be set.
7.7.5
11-3/4 in. Liner–13,100 ft. BRT
Minimum setting depth provides an acceptable kick tolerance (96 bbl) while drilling to the 9-5/8 in. casing point. Kick tolerance will be re-evaluated based on actual leak-off and drilling fluid densities required to drill the next section. Optimum setting depth is planned above the secondary objective.
7.7.6
9-5/8 in. Casing–17,200 ft. BRT
Minimum setting depth provides an acceptable kick tolerance of 55 bbl while drilling to the 7 in. casing point. Casing must be set above an objective formation prognosed at 17,400 ft.
7.7.7
7 in. Liner–21,000 ft. BRT
The optimum setting depth for the 7 in. is based on reducing the amount of 6 in. hole to be drilled while maintaining acceptable kick tolerance at the 9-5/8 in. casing shoe. At 21,000 ft., a gas kick back into casing of 33 bbl can be handled while drilling to TD for the well (22,500 ft.). Actual setting depth will be finalized based on actual drilling fluid densities required and the 9-5/8 in. leak-off test. EPT Drilling
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Equivalent Mud Weights – ppg 8
9
10
11
12
13
14
15
16
Casing / Liner Depths
5000
6123'
Water Depth 5832'
7000 Fracture Gradient
7880'
9000
Depth (feet)
9650'
11,000
11,200'
13,000
13,100'
15,000 Pore Pressure (Seismic)
Mud Weight
17,000
17,200'
19,000 21,000'
21,000 23,000
BPAD003_034.ai
Figure 7.9. Anticipated Mud Weights/Fracture Gradients, Keathley Canyon 255 No. 1 Example
7.8
Sizing Tubulars
Determination of casing setting depths essentially fixes the length of each tubular. A related issue prior to actually beginning a tubular design is the size of the string.
7.8.1
Production Tubing
Tubular sizing proceeds from the inside, out. The production tubing is the most important tubular to size, as the production associated with an optimized tubing string diameter will easily outweigh any cost of subsequent casing sizes. Production tubing sizing is a flow assurance task, usually determined by nodal analysis software the combines the inflow performance of the reservoir, the multiphase pressure drop in the tubing and the configuration of the surface gathering system.
7.8.2
Production Casing
Once the production tubing has been sized, the diameter of the production casing is determined by a conversation with the completion and production engineers to include, as a minimum, the following: • Multiple/dual completions–How many tubings will be installed in the production casing? • Safety and lift equipment – Particularly in high flow rate wells, the size of the subsurface safety valve is often the determinant of the required diameter of the production casing. EPT Drilling
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– Does the current or future completion design include gas lift? What control lines and other conduits will be necessary to satisfy completion requirements? • Provision for washing over the tubing–In the event of a tubing failure, has provision been made for easy recovery of the fish and accessories? • Exploratory deepening–An increasingly common practice is to deepen existing wellbores to additional horizons while using existing well infrastructure. Have such issues as external corrosion, drilling wear and potentially higher pressure and temperature requirements been adequately considered in the event a future deepening is planned?
7.8.3
Intermediate and Surface Casing
Following the sizing of the production casing subsequent casing sizes follow two general rules: • The clearance between the casing and its confining hole should be 1-1/2 in. (38 mm) or greater. Although this criterion is often violated (for example, running 7-5/8 in. casing in an 8-1/2 in. wellbore), 1-1/2 in. (38 mm) is a generally accepted minimum clearance necessary to construct a robust cement sheath. In some instances, this recommendation is violated in the casing/casing annulus, but adhered to in the open hole by the practice of underreaming. • The selection of the next tubular (to be installed in a specific confining hole) or bit (to be run through a specific casing) should, whenever possible, use standard sizes. Again, there may be instances when this recommendation is violated, an example being the use of non-standard tubular sizes when the number of casings to be installed in a well pushes the limits of the available radial clearance9 . Tables 7.6 and tab:sizing table SI may be used to size both tubulars and bits, given the above guidelines. Viewing either table the columns are, from left to right, • The specified outside diameter of standard tubulars, or groups of tubulars; • The bit size normally used to drill the next hole section; • The next tubular size if the 1-1/2 in. diametric clearance rule is to be honored; • The alternate maximum tubular size that should be run. Using either table proceeds from bottom to top, and from right to left. Consider, for example, that discussions with the completion/production engineer have determined that an appropriate size for the production casing is 4-1/2 in. (114.3 mm). Assume that the recommended 1-1/2 in. (38 mm) clearance is to be honored. Near the bottom of each table, in the third column, we find 4-1/2 in. (114.3 mm) tubes. Reading from right to left, the appropriate bit size is 6.125 in. (155.6 mm), and the previous casing size should be 9 Deep
water applications are usually limited by the extremes of the bore of the 18-3/4 in. high pressure wellhead on the outside and the approximately 9-1/2 in. diameter of the subsurface safety valve on the inside. Between these boundaries, a large number of casings may be necessary to accommodate the notoriously narrow window between pore pressure and fracture gradient.
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Table 7.6. Sizing Table for Tubulars and Bits–Traditional Units Nominal OD (in.)
Standard Bit Size, Drift Diameter (in.)
36.000
33.000
Recommended Next Nominal OD (in.) 30.000
Allowable Next Nominal OD (in.)
-
26.000
30.000
24.000
26.000
-
20.000 22.000 24.000
16.000
18.625
16.000
-
or 20.000
14.000 20.000
17.500
13.625
16.000
13.375
16.000
14.750
14.000 13.625
12.25
11.875
14.000
11.750
13.625
10.750
13.375
9.875
11.875
9.625
11.750
13.375 11.875
10.750
10.625
8.625
11.750
9.875 9.625
9.500
7.750
8.625
7.625 10.750
or 8.750
7.000
7.750 7.625
9.875
8.500
7.000
7.750
6.625
7.625
7.875
5.500
6.625
7.875
5.500
6.625
6.500
5.000
5.500
7.750
6.500
5.000
5.500
7.625
or 6.125
4.500
5.000
6.125
4.500
5.000
5.875
4.000
4.500
5.875
4.000
4.500
4.750
3.500
4.000
4.750
3.500
-
9.625 or
8.625
7.000
6.625
5.500
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Table 7.7. Sizing Table for Tubulars and Bits–SI Units Nominal OD (mm)
Standard Bit Size, Drift Diameter (mm)
914.4)
838.2
Recommended Next Nominal OD (mm) 762.0
Allowable Next Nominal OD (mm)
-
660.4
762.0
609.6
660.4
-
508.0 558.8 609.6
406.4
473.1
406.4
-
or 508.0
355.6 508.0
444.5
346.1
406.4
339.7
406.4
374.6
355.6 346.1
311.1
301.6
355.6
298.4
346.1
273.0
339.7
250.8
301.6
244.5
298.4
339.7 301.6
273.0
269.9
219.1
298.4
250.8 244.5
241.3
196.9
219.1
193.7 273.0
or 222.2
177.8
196.9 193.7
250.8
215.9
177.8
196.9
168.3
193.7
200.0
139.7
168.3
200.0
139.7
168.3
165.1
127.0
139.7
196.9
165.10
127.0
139.7
193.7
or 155.6
114.3
127.0
155.6
114.3
127.0
149.2
101.6
114.3
149.2
101.6
114.3
120.6
88.9
101.6
120.6
88.9
-
244.5 or
219.1
177.8
168.28
139.7
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7 in. (177.8 mm). Now returning to the third column, we find size 7 in. (177.8 mm) three table divisions higher in the column. Again reading from right to left, the appropriate bit size is 8.500 in. (215.9 mm), and the previous casing size should be either 9.875 in. (250.8 mm) or 9.625 in. (244.5 mm). The process is continued toward the top of the table, depending on the number of intermediate and surface casings to be run.
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Chapter 8
Collapse Design Criteria 8.1
Design Issues for Collapse
Collapse refers to a design scenario where the external pressure is greater than the internal pressure, and the pipe can fail due to instability of its cross section. A collapsed cross section can trap or damage inner tubulars or completion components. The reduction in collapse resistance by axial tensile stress is incorporated in collapse design analysis. The increased collapse resistance due to axial compressive stresses may be considered, but is customarily ignored unless the presence of the compression can be assured. Particularly in deviated wellbores, where friction
Figure 8.1. Collapsed 16 in. casing recovered from Pompano A-31
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can influence the local value of axial load, dependence on a compression-enhanced collapse resistance is a questionable design practice. Comparison of triaxial stresses with yield stress under collapse loading is only relevant to tubulars where the ratio of outside diameter to thickness (D/t) is less than approximately 15. For higher D/t ratios, instability rather than yield is the governing criterion. The collapse design factor usually governs for collapse loads. An acceptable triaxial design factor does not guarantee adequate collapse resistance. API/ISO collapse values should be used for casing performance rating unless high collapse premium casing is purchased from a qualified manufacturer(s). In the latter case, alternate collapse values can be used but should be adequately documented by experimental results and statistical analysis.
8.2
Calculating Collapse Pressure Design Factors
To calculate the collapse pressure load (pc ), evaluate 2t pc = po − 1 − pi . (8.1) D Equation 8.1 is an approximation used to translate the internal and external pressure to the mid-surface of the tube cross section, a process that may create inconsistencies. For example, consider the bottom of a tubular hanging open-ended in a deep wellbore. In actuality, the stress state in the tube at the critical inner radius is hydrostatic and benign, i.e., σa = σr = σh = −pi , and the equivalent stress σe vanishes. However, Equation 8.1 suggests that as depth increases, even with equal internal and external pressures, the collapse differential pressure increases. Typically, this anomaly will not be large enough to cause serious concern; however, for deep tubulars with high D/t values, such as solid expandable tubulars (SETs), the effect on design could be appreciable. For such thin tubes, the collapse pressure load may be defined using simple differential pressure, pc = po − pi ,
(8.2)
although the D/t at which this simplification is applicable is somewhat uncertain. As a general rule, Equation 8.2 should be applicable to all cross sections which collapse in the elastic collapse mode (see Section 8.4.2.1). The design requirement for collapse pressure is API/ISO Collapse Rating , (8.3) DFc is 1.0 for new casing and all tubing (or see Chapter 13), and DFc ≥ 1.0 for casing and DFc ≥ 1.1 pc ≤ fwear ×
where fwear
for tubing under both test and service conditions.
8.3
Installation Loads
Installation loads for casing and tubing differ significantly. Whereas casing may suffer a substantial collapse pressure differential during installation, tubing is usually installed with the same fluid both internal and external to the tube. EPT Drilling
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Figure 8.2. Collapse loadings for casing installation (cementing).
8.3.1
Casing Installation (Cementing)
For casing strings, the design installation collapse load is due to the differential pressure at any depth created by the hydrostatic pressure of the annulus fluids and the displacement fluid density inside the casing. The annulus fluids can be a combination of drilling fluid, spacer(s), and lead and tail cement. This loading is of particular concern for large diameter casing with high D/t ratios. For conventional cement jobs as shown in Figure 8.2, the collapse loading at any depth is equal to the hydrostatic pressure exerted by the annulus fluids above that depth less the hydrostatic pressure inside the casing. To calculate the annulus hydrostatic pressure (po ) for the installation load, evaluate
po [psi] = γm [ppg] × hm [ft TVD] × 0.052 + γs [ppg] × hs [ft TVD] × 0.052
(8.4a)
+ γc [ppg] × hc [ft TVD] × 0.052, or in Hybrid units,
po [psi] = γm [SG] × hm [m TVD] × 1.4206 + γs [SG] × hs [m TVD] × 1.4206
(8.4b)
+ γc [SG] × hc [m TVD] × 1.4206, or in SI units, EPT Drilling
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po [MPa] = γm kg/m3 × hm [m TVD] × 9.80665 × 10−6 + γs kg/m3 × hs [m TVD] × 9.80665 × 10−6 + γc kg/m3 × hc [m TVD] × 9.80665 × 10−6 .
(8.4c)
Equation 8.4 determines the annulus hydrostatic pressure at the bottom of the casing. Appropriate adjustments should be made for other locations in the string. For conductor casing with returns taken at the sea floor, the hydrostatic pressure of the sea water is added to the above equation. To calculate the hydrostatic pressure inside the casing (pi ), evaluate pi [psi] = γm [ppg] × hm [ft TVD] × 0.052,
(8.5a)
pi [psi] = γm [SG] × hm [m TVD] × 1.4206,
(8.5b)
pi [MPa] = γm kg/m3 × hm [m TVD] × 9.80665 × 10−6 .
(8.5c)
or in Hybrid units,
or in SI units,
Even for conventional cementing, the beneficial effect of the internal circulating pressure is ignored. The collapse calculation occurs at a time when this pressure can be zero, e.g., during waiting-on-cement (WOC). For cementing stab-in jobs as shown in Figure 8.2, the collapse loading at any depth is calculated in the same manner as the conventional cement job with one exception. Since circulation is accomplished through an inner string, the circulating pressures are not applied to the inside of the casing. If the annulus begins to bridge during circulation, the increase in pressure will be directly applied to the casing externally but not internally. Consequently, Equation 8.4 would be adjusted to include the bridging pressure by
po [psi] = γm [ppg] × hm [ft TVD] × 0.052 + γs [ppg] × hs [ft TVD] × 0.052
(8.6a)
+ γc [ppg] × hc [ft TVD] × 0.052 + pressure due to annulus bridging, or in Hybrid units,
po [psi] = γm [SG] × hm [m TVD] × 1.4206 + γs [SG] × hs [m TVD] × 1.4206
(8.6b)
+ γc [SG] × hc [m TVD] × 1.4206 + pressure due to annulus bridging, or in SI units, EPT Drilling
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po [MPa] = γm kg/m3 × hm [m TVD] × 9.80665 × 10−6 + γs kg/m3 × hs [m TVD] × 9.80665 × 10−6 + γc kg/m3 × hc [m TVD] × 9.80665 × 10−6
(8.6c)
+ pressure due to annulus bridging.
The casing design for a stab-in cement job should consider the possibility of annulus bridging, and the maximum annulus bridging pressure for the proposed casing should be determined and used to establish any limitations on cementing pressure.
8.3.2
Tubing Installation
Tubing is usually installed open-ended in a single fluid medium. It is not, therefore, normally necessary to consider collapse loading during tubing installation. Care should be taken, however, to insure each design does not violate this assumption.
8.4
Post-Installation Collapse Loads
For all casing collapse loads during drilling, the external pressure will be the hydrostatic pressure due to the drilling fluid used to set the casing. Drilling fluid weight is proposed due to the following: • Uncertainty of complete cement isolation due to high angle channeling and washed out hole sections (cf. Figure 8.3). • Exposure time during drilling is usually less than six months. Drilling fluid settling may be minimal, thus maintaining drilling fluid hydrostatic. • Using the cement density itself as part of the hydrostatic pressure calculation is probably too conservative. If the cement in the external fluid column has not properly set (e.g., green cement), it may be assumed that remedial action will be taken to alleviate this circumstance. The undisturbed temperature profile shall be used as both the initial and final temperature distribution. Although many collapse loads occur at a time when the wellbore is heated, assuming a long exposure time leading to a possible return to the initial, undisturbed temperature is conservative in that it places the maximum tension in the tubular, thereby reducing collapse resistance. The collapse design factor for all casing or liners shall be DFc ≥ 1.0 and for tubing shall be DFc ≥ 1.1.
8.4.1
Conductor Casing (Exploration and Development)
For casing exposed to drilling ahead, if a lost circulation (LC) zone is encountered during drilling, the drilling fluids will leave the wellbore and begin bleeding into the LC zone. In the extreme, the fluid level in the wellbore will fall in consequence until the pressure in the wellbore adjacent to the LC zone equalizes to EPT Drilling
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Figure 8.3. Cement Channels and Washed-Out Hole Sections
the pressure in the LC zone. There will be occasions where this load case gives rise to very high collapse pressures. The degree to which the fluid level in the wellbore will fall in this scenario depends upon both the depth and the pressure in the LC zone. For design, this depth-pressure combination is chosen to result in the maximum fall of fluid level. For drilling during lost circulation, the internal hydrostatic pressure is the lower of the conditions listed below: 1. For offshore or onshore wells with sufficient water supply, the lowest internal hydrostatic pressure can be seawater or fresh water, as appropriate. 2. For areas where a known LC zone is present (cf. Figure 8.4), the depth of evacuation will be sufficient to balance the LC zone hydrostatic pressure with the drilling fluid weight during drilling at a known depth or TD of the deepest subsequent open hole (DSOH), zm =
γm − γf γm
zLC .
(8.7)
If no known loss zones exist then take zLC as the TVD of the DSOH. 3. Complete evacuation during air or foam drilling. If a lost circulation zone is encountered as discussed, the fluid level in the annulus will drop. If a marine riser is employed, as the fluid drops, the collapse pressure on the riser will increase. The riser worst case with EPT Drilling
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Figure 8.4. Collapse Load while Drilling into LC Zone (No Top-Up Water Supply Available)
Figure 8.5. Collapse Load due to Partial Evacuation to DSOH
high drilling fluid weights could be when the annulus fluid level drops to below the seabed and the inside of the riser is totally “dry”. At that moment, the collapse load case at the base of the riser is the seawater pressure at the seabed. The D/t ratio of a typical riser is normally high, and in deep water riser collapse criteria must be taken into account. Do not treat the casing in isolation. Riser design is not covered in this manual and appropriate advice should be sought from EPT. When a liner is run, collapse loads must be considered for both casing and liner to the depth at which the next full casing string will be run, see Figure 8.5. 8.4.1.1
Surface Casing (Development)
For a service life load of drilling lost circulation the internal hydrostatic pressure should be based on experience in the area. As a minimum surface casing loads for development wells follow the same considerations EPT Drilling
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as listed for conductor casing: 1. For offshore or onshore wells with sufficient water supply, the lowest internal hydrostatic pressure can be seawater or fresh water, as appropriate. 2. For areas where a known LC zone is present, the depth of evacuation will be sufficient to balance the LC zone hydrostatic pressure with the drilling fluid weight during drilling at a known depth or TD of the deepest subsequent open hole (DSOH), zm =
γm − γf γm
zLC .
(8.8)
If no known loss zones exist then take zLC as the TVD of the deepest subsequent open hole (DSOH). 3. Complete evacuation during air or foam drilling. 8.4.1.2
Surface Casing (Exploration)
In principle the loadings are as for the development well Case 2 (of Section 8.4.1.1) but with the more onerous requirement of assuming a normally pressured loss zone at the TD of the DSOH. The depth of evacuation is to be calculated on the basis of the expected drilling fluid weight at TD of the DSOH. 8.4.1.3
Intermediate Casing/Liners
Collapse loads for intermediate casing and liners are the same as surface casing loads for exploration and development wells as discussed in Sections 8.4.1.1 and 8.4.1.2. 8.4.1.4
Production Casing, Liners and Tiebacks
Service life loads for production tubulars must consider all future completion techniques which could cause collapse loads (e.g., gas lift or ESPs). For these long term loads occurring in the future some relaxation from the use of the drilling fluid density as the external pressure is permitted. For collapse design it is assumed that drilling fluids in uncemented casing to casing annuli and in cemented annuli maintains solids suspension indefinitely. For casing exposed to formation via cement it is assumed that the external pressure is equivalent to drilling fluid weight for the first year but reverts to pore pressure thereafter. This approach assumes the cement sheath will provide the necessary additional stability if the external pressure is still between drilling fluid weight equivalent and pore pressure after one year. Figure 8.6 provides a summary of external hydrostatic pressure assumptions. The internal pressure differs between above and below the packer. See Figure 8.6. 8.4.1.4.1
Above the Packer
Internal hydrostatic pressure should consider:
1. The highest density completion fluid fallen to a level which balances the lowest expected reservoir pressure, e.g., a packer leak near depletion. 2. The lowest completion fluid weight during the life of the well. Consider seawater if it may be used to displace the cement or if anticipated for work-over fluids after bottom hole pressure depletion. EPT Drilling
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Figure 8.6. External Hydrostatic Pressure Loads - Production Tubulars
3. For gas lift operations the internal pressure profile shall be that arising from a column of gas between the surface and the deepest gas lift mandrel (GLM). The surface pressure above the gas column shall be the lowest that is expected during operations. The use of a surface pressure higher than atmospheric should be justified by a detailed review of production operation procedures, the effect of any annulus safety valves (ASVs) and possible work-over requirements. ASVs are generally regarded as not reliable enough to ensure that annulus surface pressure stays higher than atmospheric. The internal pressure profile below the lowest gas lift mandrel shall assume completion fluid in the casing, unless (2) above is more onerous. 4. Other completion operations shall be considered in detail to derive additional appropriate loading criteria. External hydrostatic pressure: • For the first year, the drilling fluid density used to set the production casing. • After the first year, the appropriate load as defined below is recommended: EPT Drilling
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(a) Pore pressures where casing is radially exposed to formation via cement. (b) Hydrostatic pressure of the drilling fluid used to set the production casing above the cement top. 8.4.1.4.2
Below the Packer
Internal hydrostatic pressure is based on:
1. A gas gradient from atmospheric surface pressure (e.g., blocked perforations). This load case can be modified based on produced fluids gas/oil ratio and effective density gradient at atmospheric surface pressure. 2. For gas lift operations, full evacuation to the lowest depth of gas lift mandrels with the effective produced fluid gradient from the lowest mandrel to TD. 3. For pumping operations (ESPs, rod pumps, jet pumps, etc.), low suction pressures can be generated. ESPs and rod pumps in particular are capable of drawing a vacuum if required or during certain upset conditions. Close collaboration with the completion engineer and or pump provider is required to fully define the worst case (lowest) bottom hole pressure that can be generated below the pump. 4. Other completion or production operations can generate low pressures below the packer. The same assumptions used in the tubing design must be communicated with the casing designer in this critical area. One example of low pressures is the use of a liner set injection valve during gas injection operations. Under these conditions, it is possible that a full evacuation of the tubing could occur. External hydrostatic pressure is identical to the “Above the Packer” (Section 8.4.1.4.1) load conditions. 8.4.1.5
Production Tubing
Tubing can be subject to high collapse loads under certain conditions. High collapse loads are normally only present when there is a seal (packer or liner seal) and there are no live gas lift valves. The worst place for collapse is usually immediately above the packer or liner seal. Collapse is usually caused by a combination of low internal pressures and/or high “A”1 annulus pressures. The undisturbed temperature profile shall be used as both the initial and final temperature distribution. Although many collapse loads occur at a time when the wellbore is heated, assuming a long exposure time leading to a possible return to initial, undisturbed temperature is conservative, in that it places the maximum tension in the tubular, reducing collapse resistance. 8.4.1.5.1 stances:
Low Internal Pressures
Low pressures internal to the tubing can occur in the following circum-
• The worst case is a gas gradient from atmospheric surface pressure, which is often modeled as full evacuation of the tubing. This is possible if the perforations or liner becomes blocked and there is a column of gas in the tubing. This condition may also be possible with a tailpipe or liner deployed injection valves and gas injection operations. 1 This
manual follows the convention of labeling annuli in succession proceeding radially outward from the tubing, with the tubing by production casing annulus being Annulus “A”.
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• Low internal pressures can be generated by high drawdowns or low (e.g., near abandonment) reservoir pressures. • Pumps may generate low suction pressure immediately below the pump. This point may be inside tubing or casing. 8.4.1.5.2
High “A” Annulus Pressure
High pressures external to the tubing can occur in the following
circumstances: • Where the “A” annulus is accessible, the highest pressure that should be considered during normal production operations is the maximum allowable annulus surface pressure (MAASP) on the “A” annulus. This value will be derived from the tubing collapse or casing burst limits, and this pressure is proceduralized into well site operations. In the event that this pressure is exceeded, there will either be manual or automatic actions taken to vent or control the pressure. During production start-up, thermal expansion will likely lead to higher pressures than the MAASP and this must be controlled. • An “A” annulus pressure test often imposes high collapse loads on the tubing. It is important to understand what is being tested and why. The annulus test is not designed to test the casing. Any casing test should have been performed prior to installing the completion. After all a casing leak at this point in the program would not be timely. Likewise the annulus test is not primarily a test of the collapse resistance of the tubing. The leak direction for hydrocarbons is in the other direction. The annulus test may be a test of the packer or liner top PBR seal, but this seal is normally (and preferably) tested from the direction it will see hydrocarbons, e.g., from below. In some circumstances, a packer test is only possible from above–examples would include a non-isolated sand screen completion. This, therefore, leaves the only purpose of the annulus test being to test the hanger from below. This is a critical test, as although some hangers can be tested through test ports, only the annulus test loads the hanger from below. The annulus test should be to the same pressure to which the casing has been tested, as the hanger is part of the same barrier system. This test can result in high collapse pressures on the tubing. As the test is not primarily designed to test the tubing, it is acceptable to back up the test with simultaneous pressure inside the tubing. • “A” annulus pressure in combination with tension may be an issue. Consider a scenario where (a) a well is shut-in for a considerable time, (b) a down hole tube or accessory develops a leak, (c) reservoir pressure migrates in the annulus to the wellhead, and (d) the well is placed on production without venting the pressure from the leak. The internal tubing pressure may not be as low as other cases considered here, but the collapse pressure differential, in combination with the tension (reducing collapse resistance) at the top of the string, may be sufficient to collapse the tubing. This load case can be prevented by alertness to “A” annulus pressure, but has been known to collapse tubing.
8.4.2
Determining the Appropriate Collapse Rating
The following notes provide a brief overview of the API TR 5C3 or ISO TR 10400 [9] approach to collapse pressure ratings. This document and specialists within EPT should be consulted for the determination of collapse resistance of non-standard tubulars. EPT Drilling
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Figure 8.7. Calculated Collapse Pressure Resistance for N80 Tubulars
8.4.2.1
Uniform Loading
The nature of a tube’s collapse behavior depends on its D/t ratio. For low D/t ratios, failure is governed largely by yield on the inner surface of the tube. For high D/t ratios, it is governed largely by elastic instability. For intermediate D/t ratios, collapse occurs by elasto-plastic instability. In the API/ISO design approach, these are termed “yield strength collapse” (for low D/t ratios), “elastic collapse” (for high D/t ratios), and “plastic collapse” (for intermediate D/t ratios). There is a fourth collapse mechanism termed “transition collapse”. This is a fictitious mechanism which has been devised to link the minimum plastic collapse curve to the minimum elastic collapse curve. This anomaly is due to the fact that the expected intersection between the elastic and plastic collapse modes is lost when moving from average collapse behavior to minimum (design) collapse behavior. Figure 8.7 shows the typical collapse modes plotted against D/t for Grade N80 material. Collapse ratings only apply to uniform external pressures, they may not be relevant for non-uniform loadings (e.g., salt creep) or for uniform loads that are not attributable to a fluid pressure. Collapse performance of connections is assumed to exceed that of the adjacent pipe body. The API collapse rating of a tube is calculated by the following procedure which must first be carried out in English units, and then, if desired, the final answer may be converted to Metric units: • Compute a “reduced yield stress” fyax to account for the presence of the axial tension according to EPT Drilling
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the formula s
fyax = 1 − 0.75
σa fymn
2
σa − 0.5 fymn . fymn
(8.9)
The above equation is obtained from the von Mises yield criterion applied to a biaxial state of stress. It is, therefore, strictly applicable to situations where yield is the sole mode of deformation and no cross-sectional instability is present. Thus the reduced yield stress is only valid for yield strength collapse where the failure is governed by yield. As such it is only applicable to casings with D/t ratio < 15, but is frequently applied to higher D/t ratios where it is conservative. If the tubular is in axial compression at the depth of the collapse calculation, fyax will be greater than fymn . In almost all instances, the more conservative view should be taken, that is, set fyax = fymn . The less conservative view of increasing collapse resistance in the presence of axial compression should only be considered when one can ensure that the axial compression will be present. If the tubular is subjected to bending in addition to axial tension, the maximum combined stress (σa +σb ) should be used as the axial stress value. • Compute the empirical constants Ac , Bc , Cc , Fc and Gc
2 3 , Ac = 2.8762 + 0.10679 × 10−5 fyax + 0.21301 × 10−10 fyax − 0.53132 × 10−16 fyax
(8.10)
Bc = 0.026233 + 0.50609 × 10−6 fyax ,
(8.11)
2 3 Cc = −465.93 + 0.030867fyax − 0.10483 × 10−7 fyax + 0.36989 × 10−13 fyax ,
(8.12)
B 3 3 c 46.95 × 106 2+ABcc Ac Fc = B 2 , c c 3 Ac 3B Bc Ac fyax 2+ Bc − Ac 1 − 2+ Bc
(8.13)
Ac
Ac
Gc =
Fc Bc . Ac
(8.14)
The above equations for the empirical constants do not account for the adjustment of collapse resistance for axial load. If the reduced yield stress calculated in the previous step is less than fymn , use fyax instead of fymn when computing the empirical constants. • Compute the D/t boundary for each of the recognized collapse formulas
(D/t)yp
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r 2 c (Ac − 2) + 8 Bc + fC + (Ac − 2) yax = , c 2 Bc + fC yax 135
(8.15)
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Table 8.1. Collapse Mode Boundaries for D/t Ranges Yield Stress
Yield/Plastic
Plastic/Transition
Transition/Elastic
(ksi)
Boundary, (D/t)yp
Boundary, (D/t)pt
Boundary, (D/t)te
40
16.40
27.01
42.64
55
14.81
25.01
37.21
75
13.60
22.91
32.05
80
13.38
22.47
31.02
90
13.01
21.69
29.18
95
12.85
21.33
28.36
110
12.44
20.41
26.22
125
12.11
19.63
24.46
(D/t)pt =
fyax (Ac − Fc ) , Cc + fyax (Bc − Gc )
(D/t)te =
2+
Bc Ac
c 3B Ac
,
(8.16)
(8.17)
where the subscripts designate the respective collapse modes as yield (y), plastic (p), transition (t), and elastic (e). For example, (D/t)pt is the D/t boundary between the plastic and transition collapse formulas. For a quick look at the collapse mode boundaries and D/t ranges, see Table 8.1. All assume no axial stress. Values of D/t denote the boundaries between API collapse modes. • Compute the D/t of the current tube and determine the appropriate collapse formula by comparing this value to the D/t formula boundaries of the previous step. • According to the collapse mode, compute the collapse performance from one of the following formulas:
pY = 2fyax Ac
pP = fyax
D t
pT = fyax
pE =
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D t −1 , D 2 t
− Bc Fc D t
!
− Gc
− Cc ,
(8.19)
!
(8.20)
46.95 × 106 2 . D D t t −1 136
(8.18)
,
(8.21)
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• The result of the above calculation is a collapse pressure, pc . The elastic collapse mode should not be reduced due to axial tension load, of particular note for risers and large diameter casing. Published elastic stability analyses show that elastic collapse of long tubes is unaffected by axial load. 8.4.2.1.1 Example Problem Given a tube of 244.48 mm (9-5/8 in.), 69.94 kg/m (47 lb/ft), N80 casing in the presence of 1,334 kN (300,000 lbs) tension and an internal pressure of 6.895x10-3 MPa (1000 psi), compute the collapse resistance. The input variables are D = 9.625 in. t = 0.472 in. fymn = 80,000 psi, σa = 22,104 psi, pi = 1,000 psi. Following the procedure outlined in this section: • The pseudo yield stress is fyax = 66,624 psi. • The empirical constants are Ac = 3.026, Bc = 0.0600, Cc = 1,555, Fc = 1.986 and Gc = 0.0394. • The D/t boundaries are (D/t)yp = 14.03, (D/t)pt = 23.71 and (D/t)te = 33.99. The D/t of the subject tube is 9.625/.472 = 20.39, and therefore, since this value falls between the Yield/Plastic and Plastic/Transition boundaries, the Plastic collapse formula governs. The collapse resistance in the absence of internal pressure is pc = 4,340 psi. With 1000 psi internal pressure the external pressure necessary to collapse the tube is (see Equation 8.1) po = pc + (1 − (2t/D))pi = 5,240 psi. Note the following: • If the axial force had been compressive instead of tensile, then the pseudo yield stress would have been set equal to the API minimum yield stress, fymn . That is, the beneficial effect of axial compression raising the yield stress would have been ignored. • Since axial stress varies along the pipe, these calculations are best left to software. 8.4.2.2
Non-Uniform Loading
BP and the industry have experienced the detrimental effects of non-uniform formation loading in a number of environments, including mobile salt [22, 24, 78], compacting chalk [74], oil sands recovery [87] and tectonic stress states [75, 50]. The collapse performance property of casing as defined by API TR 5C3 or ISO TR 10400 [9] assumes a tube to be loaded everywhere by external fluid pressure. Unfortunately, the stresses imposed by a flowing formation, e.g., salt, are not necessarily uniform and, therefore, API/ISO collapse ratings for a tube are no longer applicable (see the caution in Table 6.3). Non-uniform cross-sectional loading for two simple distributions (see Figure 8.8) shows the relative importance of key variables [68]. For unidirectional loading, the distributed load, Q, to cause yield is Q=3 EPT Drilling
fymn . ( Dt )2
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For the case of opposed line loads, the intensity, R per unit length, to cause first yield is R=
( Dt
fymn . − 1)(0.96 Dt − 0.32)
(8.23)
For both of the above cases, the resistance increases roughly as the square of the thickness to outside diameter ratio of the tube. By contrast, for conventional yield collapse of a cross section due to hydrostatic fluid pressure, the collapse resistance increases as t/D. When designing for a flowing formation that is expected to impose non uniform loading, it is better to increase wall thickness than increase the yield strength of the tube material [87, 78, 45, 57, 33, 32, 76]. To double non-uniform load resistance it is necessary to double yield strength, whereas a wall thickness increase of approximately forty percent can achieve the same effect. Increasing wall thickness to take advantage of the behavior described above leads to considering concentric configurations, a term referring to the positioning of dual casing strings, structurally connected by a cement sheath, opposite the offending rock. The intent is that the casing/cement/casing composite act as a unit to increase the effective wall thickness opposing the non-uniform loading. • Although it is not necessary that the cement element of the cross section be particularly strong, this element must be sufficiently competent to transmit loads between the casing elements. Otherwise, the cross section does not behave as a unit. As a corollary, an annular configuration with no cement is of practically no benefit. Indeed, it can be expected that with increasing load, the outer member will first fail as described above, and then, with continued deformation, impose opposed line loading on the inner casing so that a partially cemented concentric configuration can actually be weaker than the inner string by itself. • It is not necessary that the individual tubular elements of a concentric configuration be of particularly high yield strength. The emphasis in non-uniform loading is on wall thickness. One exception to this involves formations that move during the installation of the concentric configuration, a typical example being mobile salts. If the concentric configuration is being formed by a liner overlap, the outer string will have to be strong enough to resist salt movement alone until the next hole section is drilled and the overlapping liner run and cemented. • It is not necessary that the two elements of the concentric configuration be exactly concentric. Even in the worst case of the inner string eccentric and contacting the outer string, the effective wall thickness of the cross section is still increased, with resulting increased resistance to non-uniform loading. Notwithstanding the above, concentric completions are not a panacea. It is important, to ascertain the type of deformation mechanism active in a given locale, and then decide if concentric casing can mitigate that mechanism. Typical considerations that may suggest a concentric configuration to be inappropriate include: • A long, inclined section of wellbore. Cementing the concentric annulus in such a case may be difficult. If complete circumferential cement coverage cannot be guaranteed, the possibility of the outer casing collapsing into the uncemented channel and point loading the inner casing is introduced [76]. As an alternative, thick-walled casing may be appropriate. EPT Drilling
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Figure 8.8. Non-Uniform Loads Considered by Nester et al. [68]
• A concentric configuration may limit clearances. For example, a concentric configuration over a portion of the production casing string may limit the depth to which gas lift mandrels can be installed. 8.4.2.2.1 Drilling Recommendations The integrity of the wellbore, coupled with the competence of the cement sheath, can significantly affect tubular resistance to non-uniform loading. Although BP casing designs opposite mobile formations do not allow the designer credit for a competent cement sheath, drilling practices can contribute to the long term integrity of the well cross-section. In most cases, the effect of the drilling practice is to minimize the non-uniform nature of the load. Drilling practices that mitigate the effects of non-uniform loading include the following: • Run caliper logs on all logging suites to determine the rate at which the formation moves. • Where the rate of movement is likely to be high, drill or underream an oversized hole. This will maximize the time before the movement results in formation-casing contact. • In those operations where the rate of formation movement is unknown an oversize bit should be used. This will reduce the incidence of stuck pipe and so help prevent hole enlargement through the course of fishing and pumping fresh water pills. In addition it will maintain a larger annulus for cement displacement. • Drilling operations that could increase dog leg severity in the section should be avoided. • Specifically, for mobile salts: – In areas where high rates of salt movement are apparent, ensure the hole is as round and as close to gauge as possible. Washouts are known to increase the effects of non-uniform loading. The use of oil-based muds is currently accepted as standard in BP operations of this type. If future legislation prevents their use, then saturated salt muds should be viewed as the first alternative choice. – An increase in drilling fluid density is the only physical means available to control the rate of salt movement. The success of the technique is limited to those areas where the rate of movement is EPT Drilling
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comparatively low. If the salt is transmitting a significant portion of the overburden and liable to rapid movement this treatment is likely to be ineffective. • Cementing practices: – In cases where high rates of formation movement are common the only method of preventing the application of non-uniform loads on the casing are the use of slurries designed specifically to develop high early compressive strengths. – No reliance should be placed on squeeze techniques to correct poor primary cement jobs. Experience has shown that the quality of the bond required by the cement in these instances is insufficient to prevent subsequent casing problems. – In sections where mixed brine flows are known to occur the reaction of these with the final cement types should be checked. The failure of cement in place will allow both the development of high non-uniform loads and corrosion to shorten the casing life. High weight dispersed slurries composed of neat cement tend to produce a final cement sheath that is less permeable than that resulting from thicker slurries. It is possible that this type of cement can help prevent failure of the casing by inhibiting the contact of corrosive brines with the string. – The casing must be well centralized across all mobile sections. The key to prevention of nonuniform loading of the casing is the provision of a competent cement sheath around the entire string. Poorly centralized casing will allow wall and consequently formation contact with the string. – Specifically, for mobile salts: ∗ The displacement of cement across the entire salt section must be achieved in order to prevent high non uniform loads on the string. This requires good displacement techniques and slurries and spacers engineered to prevent wellbore enlargement. The need for long term stability of the final cement is also apparent. Casing collapse from the effects of salt movement have been recorded up to to 15 years after completion of the well. ∗ The displacement type should be tailored to the formulation of the spacer and slurry. The wrong type of displacement in these circumstances can produce both washouts of the salt and poor mud displacement. In general, the use of high salt levels in slurries and spacers allows displacement at a wide range of rates. Typically, this would mean salt levels in excess of 15%. The use of low salt or freshwater based slurries and spacers requires careful regulation of flow rates to avoid excessive washouts. Some evidence suggests that salt incorporated while displacement has less effect upon the solution than that dissolved in the mixed water. However, the potential effect upon thickening time should be carefully considered. ∗ The CBLs run across each casing string should be analyzed in conjunction with the calipers and litho logs to determine if any particular hole sections or hole sizes are resulting in cementing problems. This information should be used to modify the future drilling and cementing program. EPT Drilling
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8.4.3
High Collapse Casing
The achievement of collapse ratings usefully in excess of the API TR 5C3 or ISO TR 10400 [9] rating depends on control of metallurgy, residual stress and pipe dimensions. EPT does not necessarily endorse ratings for high collapse published by individual manufacturers. EPT does, however, possess tools which, in concert with experimental collapse test results, can be used to arrive at higher ratings than those published in accord with API TR 5C3 or ISO TR 10400 [9]. An example of such a calculation is presented in Section 16.5.2. High collapse casing is of only small benefit for non-uniform loading, and normally should not be considered in those situations.
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Chapter 9
Burst Design Criteria 9.1
Design Issues for Internal Pressure
Burst loads are those where the internal pressure exceeds the external pressure on the tube or connector. A burst failure occurs as a (usually longitudinal) split in the tube wall. The term “burst” is unfortunate in that it is used for a variety of limit states, from initial yield of the tube body to complete rupture. The API, for example, does not use the term “burst” in order to avoid this confusion. Almost without exception, BP designs for internal pressure are based on initial yield of the tube cross section. The reduction in internal yield pressure resistance by axial compressive stress is incorporated in internal pressure design analysis. The increased internal pressure resistance due to axial tensile stresses may be considered, but is customarily ignored unless the presence of the tension can be assured. Particularly in deviated wellbores, where friction can influence the local value of axial load, depending on a tension enhanced internal pressure resistance is a questionable design practice. For casing, internal pressure loads naturally arise as drilling fluid density increases while drilling ahead. However, the most severe internal pressure loads are usually those associated with an influx of lower density fluid into the wellbore especially from an unexpected deeper, higher pressure zone. Causes of such influxes and how to deal with them are considered in the BP Well Control Manual [15]. In a casing design it is necessary to decide what internal pressure casing may be called on to resist and what grade and thickness is needed to do this. For completion design, burst conditions may be experienced during a variety of intentional or unintentional operations on tubing. Burst conditions may be worst at the top or bottom of the string depending not only on the internal fluid, but also the external fluid (e.g., lift gas) and the position of plugs or closed valves. Local regulatory agencies, e.g., MMS in the Gulf of Mexico, may impose specific local criteria which differ from those in this manual. Nevertheless wherever possible, casing design in BP should: • Provide casing stronger in internal pressure resistance than the fracture pressure of exposed formation beneath the shoe; EPT Drilling
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Figure 9.1. Ruptured Casing from Connection Test with internal pressure
• Take account of the possibility of a hydrocarbon column to the wellhead. These two aims lead to BP’s internal pressure design starting point of gas to surface from fracture pressure at shoe. In some circumstances business units may choose to use a less onerous gas kick profile criterion. This is discussed in more detail later. BP tubulars are procured to specific tolerances (refer to Chapter 20). Unless additional procurement requirements are specifically imposed, API specified wall thicknesses shall be used. Additionally, drilling through casing can cause wear (refer to Chapter 13) which should be considered in design calculations. There are numerous formulae giving internal pressure resistance of casing. For the purposes of this manual: • Loadings and design factors have been chosen to suit the API internal pressure rating; • Do not use alternative internal pressure equations in place of the API uniaxial rating. The API internal pressure rating is given by EPT Drilling
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piY AP I = kwall
2tfymn . D
(9.1)
The kwall factor, given in the standard as 0.875, may be increased if tighter wall thickness requirements are imposed at procurement. These tighter inspection requirements will typically increase the cost. The yield stress is the API minimum for the particular grade, e.g., 80,000 psi for Grade L80. Use of higher yield strength values is permissible only if a higher value is specified on the purchase order and each individual pipe is tested to ensure it meets the elevated criterion1 Higher yield strengths must be obtained by destructive tensile testing of samples to measure the actual tensile yield strength (API Specification 5CT or ISO 11960), not inferred from localized hardness measurements. Some manufacturers claim “high burst rating” products. This is sometimes achieved by localized increase in yield stress at the pipe internal radius. Do not use such proprietary high internal pressure ratings in design. Internal pressure loads are often associated with buckling of uncemented sections. Consideration of the triaxial design factor is essential.
9.2
Calculating Internal Yield Pressure Design Factors
To calculate the API internal yield pressure design factor, the internal and external pressure profiles for each service load case must be calculated since the API internal pressure design factor is based on the differential pressure across the casing/tubing. For the internal yield pressure design criterion to be relevant at a particular depth, the internal pressure, pi , must be greater than the external pressure, po . The differential internal pressure, pb , at any depth is calculated by
pb = pi − po .
(9.2)
For subsea wells the external pressure at mudline will be the seawater pressure. The design requirement for internal pressure is
pb ≤ fwear × fT ×
piY AP I . DFb
(9.3)
where fwear is 1.0 for new casing, or see Chapter 13, the temperature derating factor is discussed in Chapter 14, and DFb ≥ 1.1 for casing2 and DFb ≥ 1.1 for tubing under test conditions and DFb ≥ 1.25 for tubing under service conditions. 1 It is not permissible to use higher yield strength values applicable to pipes individually identified as being from a single specific melt, heat treatment lot and processing batch. Mill certification values are insufficient, in that mill tests are a qulity check of 1 in 200 pipes in a single heat to statistically indicate that all the pipes in that heat are greater than the specified minimum value. 2 Exception:
DFb ≥ 1.0 for the default well control load load case of fracture at the casing show with a gas gradient to the
surface.
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9.3
Installation Loads
9.3.1
Running
Internal yield pressure loads do not need to be considered unless a pressure test is performed before cementing (casing) or setting the packer (tubing).
9.3.2
Casing Installation (Cementing)
Two conditions should be considered for cementing–cement displacement and bumping the plug. 9.3.2.1
Cement Displacement
During cement displacement: • po is the pressure arising from drilling fluid density external to the casing. • pi assumes spacer at the casing shoe with cement then drilling fluid density within the casing to the surface, together with the highest anticipated surface pressure during cement displacement. This surface pressure may arise from mud and cement rheology considerations or reflect an operational estimate of pressure rise associated with annulus bridging. Static pressure calculations are adequate for casing design for cementing. 9.3.2.2
Bumping the Plug
See Figure 9.2. To calculate pi , use Equation 9.43 ,
pi [psi] = piSurf [psi] + γm [ppg] × hm [ft TVD] × 0.052,
(9.4a)
pi [psi] = piSurf [psi] + γm [SG] × hm [m TVD] × 1.4206,
(9.4b)
pi [MPa] = piSurf [MPa] + γm kg/m3 × hm [m TVD] × 9.80665 × 10−6 .
(9.4c)
or in Hybrid units,
or in SI units,
External pressure shall be taken as cement followed by spacer then mud to the surface as shown in Figure 9.2. Below is an example that references Figure 9.2, performing the calculation in US Customary units. 3 In
addition to internal pressure design, the axial stresses generated when bumping the plug were, at one time, crucial in designing large diameter casing for joint strength. A previous generation of modified Buttress threads on large diameter tubulars led to a number of connection failures due to junpout during cementing. This issue has largely disappeared from industry focus with the advent of threads having negative load flanks (see Section 17.2.2).
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Figure 9.2. Cement Service Life Load - Bumping Plug
pi @ A [psi] = psurf [psi] + γm [ppg] × A [ft TVD] × 0.052, po @ A [psi] = γm [ppg] × hm [ft TVD] × 0.052,
(9.5a)
pb @ A [psi] = pi − po ,
pi @ B [psi] = psurf [psi] + γm [ppg] × B [ft TVD] × 0.052, po @ B [psi] = γm [ppg] × hm [ft TVD] × 0.052 + γs [ppg] × hs [ft TVD] × 0.052,
(9.5b)
pb @ B [psi] = pi − po ,
pi @ C [psi] = psurf [psi] + γm [ppg] × B [ft TVD] × 0.052, po @ C [psi] = γm [ppg] × hm [ft TVD] × 0.052 + γs [ppg] × hs [ft TVD] × 0.052,
(9.5c)
+ γc [ppg] × hc [ft TVD] × 0.052, pb @ C [psi] = pi − po ,
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9.3.3
Tubing Installation
Tubing is usually installed open-ended in a single fluid medium. It is not, therefore, normally necessary to consider burst loading during tubing installation. Care should be taken, however, to insure each design does not violate this assumption.
9.4
External Pressure Profiles for Casing Post-Installation Loads
The external pressure resisting burst, po , after cement has set is defined as follows: • For casing in contact with formation via cement, po is equal to the expected pore pressure, i.e., the cement is assumed to be radially permeable to formation fluids, but sufficiently impermeable to prevent axial pressure transmission. • For casing exposed to formation via an uncemented section (i.e., top of cement below shoe of previous casing) and for uncemented annuli po is the lower of (a) the pressures arising from a column of mud mix fluid to a height required to balance the lowest expected pore pressure in the uncemented area and (b) a column of mud mix fluid in the annulus with zero surface (not mudline) pressure. • For casing to casing annuli sealed by cement (i.e., top of cement above shoe of previous casing) po is pore pressure up to the previous casing shoe, and as in the preceding bullet above the shoe 4 . A higher value of external pressure may be used if it is believed that the mud will not settle significantly during the operational period of relevance. Attention is drawn to the very rapid settling time of some muds, particularly in non-vertical wells. The bilinear external pressure profile approach advocated by Vorenkamp [92] should not be used. No external radial structural support from the cement sheath and formation is to be assumed during design5 . This requirement reflects uncertainty regarding the presence of voids and microannuli, and the low Young’s modulus of rock. The external pressure profile for burst differs from that assumed for collapse. This is because the more onerous requirement in collapse is to assume that mud does not settle, while in burst it is more onerous to assume it does settle. The time and inclination limits above can be modified if appropriate using specialist advice on mud properties.
9.5
Post-Installation Casing Burst Loads
The following describes internal pressure loads for the service life of each casing string as required for development and exploration wells. To calculate the internal pressure loads which are applied to the as 4 Current StressCheck versions assume the external fluid density above the top of cement extend to the surface. For liners, this assumption wil cause the liner design to usually, and incorrectly, be governed by the liner lap. A common work-around is to use minimum pore pressure in the open hole section above the top of cement for liners. The bullet, as stated, is correct for casing strings. 5 Axial
support of cement formation relating to wellhead movement is outside the scope of this chapter.
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cemented base case, pi , po and the temperature profile are described for each casing and service life load. The external pressure for each burst load is defined in Section 9.4.
9.5.1
Conductor Casing
The following service life load is applicable to both exploration and development wells. If a leak-off test (LOT) is required, the internal pressure is based on a pressure test of casing prior to drilling out. The recommended test pressure is high enough to achieve the anticipated LOT on the casing shoe with a test margin, mtest , per Equation 9.6. piSurf [psi] = [(γLOT + mtest ) [ppg] − γm [ppg] ] × zs [ft TVD] × 0.052,
(9.6a)
or in Hybrid units, piSurf [psi] = [(γLOT + mtest ) [SG] − γm [SG] ] × zs [m TVD] × 1.4206,
(9.6b)
or in SI units,
piSurf [MPa] = (γLOT + mtest ) kg/m3 − γm kg/m3 × zs [m TVD] × 9.80665 × 10−6 ,
(9.6c)
where mtest is 0.2 ppg (0.02 SG, 24 kg/m3 ) for development wells and 0.5 ppg (0.06 SG, 60 kg/m3 ) for exploratory wells. For pi at any depth, pi = piSurf [psi] + γm [ppg] × z [ft TVD] × 0.052,
(9.7a)
pi = piSurf [psi] + γm [SG] × z [m TVD] × 1.4206,
(9.7b)
pi = piSurf [MPa] + γm kg/m3 × z [m TVD] × 9.80665 × 10−6 .
(9.7c)
or in Hybrid units,
or in SI units,
where piSurf is given by Equation 9.6.
The temperature profile for this load case is the undisturbed profile (see Section 14.2). The appropriate design factors are DFb ≥ 1.1, DFv ≥ 1.25.
9.5.2
Surface Casing
The following service life loads are applicable to both exploration and development wells. 9.5.2.1
Pressure Test
The minimum surface pressure test for a LOT, internal pressure profile, temperature and design factors are identical to those given in Section 9.5.1. EPT Drilling
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9.5.2.2
Well Control
The starting point for well control internal pressure loading is the assumption that in a suitably unfortunate combination of circumstances, the worst well control internal pressure load could be casing full of dry methane with the pressure limited by the shoe fracture pressure, piSurf = pf r − gas gradient × zs ,
(9.8)
where pf r is evaluated at zs . The temperature profile for this load case is the drilling profile (see Section 14.4). The appropriate design factors are DFb ≥ 1.0, DFv ≥ 1.25. This is a conservative loading and assumes the failure or inadequate performance of well control measures, shoe failure, continued flow without pressure depletion, and a set of mud properties and annular clearances leading to full displacement of the annular mud column by gas. There are circumstances in which application of this design rule may present difficulties. These include: • Situations of known low pore pressures, but very high fracture gradients; • When this design rule is significantly more onerous than accepted customary local practice. In such circumstances it may be appropriate to consider designing casing on a gas kick profile basis. Gas kick profile design of casing does not demonstrably satisfy the BP Drilling and Well Operations Practice. Such a choice requires formal recognition that a gas kick profile internal pressure design can represent a higher risk. As such, a policy deviation which may involve formal consideration and implementation of appropriate mitigating measures in relation to both subsurface uncertainty and drilling operation is necessary to use a gas kick profile design basis. If no hydrocarbons are anticipated seawater may be used as the influx fluid. Substantial relevant data should be available to support the assumption in design of no hydrocarbons. If there is the possibility of hydrocarbons, gas should be used as the influx fluid unless sufficient data is available to support a less onerous requirement, e.g., gas/oil.
9.5.3
Intermediate Casing
For all intermediate casings or liners, the recommended internal pressure loads after installation are the same as those for the surface casing in Section 9.5.2.
9.5.4
Production Casing
Service life loads for production casings and liners are based on completion loads for development wells and DST loads for exploration wells. 9.5.4.1
Pressure Test
For development wells, piSurf should be equal to the maximum surface pressure during production or pressures required for bullheading/fracturing down the casing. For exploration wells, piSurf should be equal to the maximum pressure required to operate DST tools or tubing conveyed firing heads. EPT Drilling
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The internal pressure at any depth can be calculated from
pi [psi] = piSurf [psi] + γm [ppg] × hm [ft TVD] × 0.052,
(9.9a)
pi [psi] = piSurf [psi] + γm [SG] × hm [m TVD] × 1.4206,
(9.9b)
pi [MPa] = piSurf [MPa] + γm kg/m3 × hm [m TVD] × 9.80665 × 10−6 .
(9.9c)
or in Hybrid units,
or in SI units,
The temperature profile for this load case is the undisturbed profile (see Section 14.2). The appropriate design factors are DFb ≥ 1.1, DFv ≥ 1.25. For production casing which has been drilled through, casing wear should be considered. 9.5.4.2
Completion Operations
For development wells, a burst load case should be developed for any specific surface pressure and fluid required for miscellaneous completion operations, i.e., fracturing, acidizing or injection. The associated temperature will depend on the completion operation. Chapter 14 describes temperature assumptions for casing during various completion operations. For all completion operations, the appropriate design factors are DFb ≥ 1.1, DFv ≥ 1.25. 9.5.4.3
Tubing Leak
For development wells, this service life design load assumes that a tubing leak occurs near the surface during production. Near surface tubing leaks from parted tubing are not frequent. However, leakage from downhole tools, packers, connections and corrosion are more frequent and can, by migration, impose pressures approaching that for a near surface tubing leak. This is a severe load case both for internal pressure and possible buckling of uncemented production casing. The maximum anticipated surface pressure, piSurf , resulting from a leak during continuous production, shut-in or injection operations is applied to the completion fluid inside the casing. For gas wells, piSurf can be calculated from
piSurf [psi] = pres [psi] − γg [psi/ft] × hm [ft TVD] ,
(9.10a)
piSurf [psi] = pres [psi] − γg [SG] × hm [m TVD] × 1.4206,
(9.10b)
or in Hybrid units,
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or in SI units,
piSurf [MPa] = pres [MPa] − γg [MPa/m] × hm [m TVD] ,
(9.10c)
where pres is the maximum expected reservoir pressure. For oil wells, replace γg in Equation 9.10 with the known fluid gradient from production operations. For injection wells, piSurf is the maximum pump dead head pressure. If the gas gradient is unknown, for reservoirs shallower than 10,000 ft. (3,000 m), use γg = 0.10 psi/ft, γg = 0.23 SG or γg = 0.00226 MPa/m; for reservoirs deeper than 10,000 ft. (3,000 m) use γg = 0.15 psi/ft, γg = 0.35 SG or γg = 0.00339 MPa/m. For the final design use a gas gradient appropriate to the expected temperature and pressure. Given piSurf from Equation 9.10 the internal pressure at any vertical depth is
pi [psi] = piSurf [psi] + γcf [ppg] × hm [ft TVD] × 0.052,
(9.11a)
pi [psi] = piSurf [psi] + γcf [SG] × hm [m TVD] × 1.4206,
(9.11b)
pi [MPa] = piSurf [MPa] + γcf kg/m3 × hm [m TVD] × 9.80665 × 10−6 .
(9.11c)
or in Hybrid units,
or in SI units,
For certain controlled operations it is possible to safely use a higher tubing pressure than the API internal yield pressure of the production casing. Such examples are common under stimulation conditions where the production casing is protected from exposure to the high tubing pressure by means of annulus monitoring, pump shutdowns and pressure relief valves on the annulus. Due allowance is made for the speed and volume relief required for the annulus to vent. Both undisturbed (Section 14.2) and production (Section 14.5) temperature profiles should be assessed to evaluate the temperature effects on the axial stress. The axial tension or compression calculations are referenced in Chapter 10. The appropriate design factors are DFb ≥ 1.1, DFv ≥ 1.25. Figure 9.3 shows the internal pressure loads for a development well with production casing set at 15,000 ft. Note the piSurf for the pressure test load was adjusted since a lower weight completion fluid was in the completion design, so a lower surface pressure was required to give a pi of 18,250 psi at 14,000 ft. 9.5.4.4
Drill Stem Test
For a DST with either gas or hydrocarbon to surface, see tubing leak load case for development wells (Section 9.5.4.3). EPT Drilling
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Production Casing Burst Loads: Development Well TD: 15,000' dp: 14,000' BHP @ 14,000': 10,920 psi (BHP EMW = 15 ppg) CF: 12ppg Produced Fluid: Gas (0.15 psi/ft) (6630) 5000 10000 MW
15000
20000
Pi (PT)
Pressure Test Load on 15.0 ppg Mud Since CF is less than MW during pressure test, the Psurf is equivalent to tubing leak load above the packer (14500') Psurf = BHP - dp(gg) (.15) = 8820psi psi Pi @ 14000' = Psurf + (CF)(d)(.052) (E6.11) Pi @ 14000' = 8820 + (12)(14000)(.052) = 17556psi
Pb (PT) Pi (TBG Leak)
For Tubing Leak Psurf = 8820 Pi @ 14000' = Psurf + (CF)(d)(.052) = 18250psi Pb = Pi – Pe for both load cases Where Pe = Pore Pressure
Pb (TBG Leak)
8.4
5000'
11
10000'
Psurf for Pressure Test on 15.0 ppg Mud Psurf = Pi @ 14000' – (15)(.052)(14000) Psurf = 17556 – 10920 = 6630 psi
TOC
13
15
15000'
(6630)
(17566)
BPAD003_063.ai
Figure 9.3. internal pressure Loads for Development Well
9.6
External Pressure Profiles for Tubing Post-Installation Loads
Unless otherwise stated, the external pressure resisting burst, po , after the packer has set is a column of completion fluid in the annulus with zero surface pressure. Important exceptions to this definition of tubing external pressure include the following: • The presence of methanol in monitoring lines; • Nitrogen gas caps; • Gas lift, with the possibility of inadvertent blow-down of the annulus.
9.7
Post-Installation Tubing Burst Loads
The following describes internal pressure for the service life loads of the tubing string. To calculate the internal pressure applied to the as landed base case, pi , po and the temperature profile are described for each service life load. 9.7.0.5
Production
The worst case for production is a production shut down with a full column of gas with the highest reservoir pressure as calculated in Equation 9.10. Under such conditions, the “A” annulus surface pressure is assumed to be zero. Production (Section 14.5) temperature profiles should be used to evaluate temperature effects on the axial stress. The axial tension or compression calculations are referenced in Chapter 10. The appropriate design factors are DFb ≥ 1.25, DFv ≥ 1.25. EPT Drilling
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9.7.0.6
Gas Lift
For gas lift cases, a scenario of maximum shut-in pressure on the tubing, coupled with full blow-down of the annulus to the depth of the deepest operating gas lift valve is possible. The use of annulus safety valves mitigates, but does not entirely avoid, the risk of full annulus evacuation. Production (Section 14.5) temperature profiles should be used to evaluate temperature effects on the axial stress. The axial tension or compression calculations are referenced in Chapter 10. The appropriate design factors are DFb ≥ 1.25, DFv ≥ 1.25. 9.7.0.7
Injection
The worst case for injection is the pump dead head pressure which is possible during a blocked liner or blocked perforations scenario. Under such conditions, the “A” annulus surface pressure is assumed to be zero. Injection (Section 14.6.2) temperature profiles should be used to evaluate temperature effects on the axial stress. The axial tension or compression calculations are referenced in Chapter 10. The appropriate design factors are DFb ≥ 1.25, DFv ≥ 1.25. 9.7.0.8
Stimulation, Transient Loads
Transient injection conditions may be observed during acid washing, proppant or acid fracture stimulation, scale squeezes or various other interventions. During such transient and controlled operations, the annulus may be controlled and pressurized to prevent over pressurizing the tubing. Profiles appropriate to the operation being modeled should be used to evaluate temperature effects on the axial stress. The axial tension or compression calculations are referenced in Chapter 10. The appropriate design factors are DFb ≥ 1.25, DFv ≥ 1.25.
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Chapter 10
Tensile Design Criteria 10.1
Tensile Design Parameters
Tensile forces should be evaluated for each service life load condition: installation, drilling, and production. For API tubulars, the pipe body tensile rating is defined as Tensile Rating = fymn Ap ,
(10.1)
where Ap is based on specified diameters. The tensile safety factor is, therefore, Tensile Safety Factor =
fymn Ap . Total Axial Force
(10.2)
Note the following: • The tensile rating may be limited to the connection rating. See Chapter 17 for connection rating details. If the connection rating is lower than the pipe body tensile rating, then the connection rating will be used as the minimum tensile rating for the casing or tubing. • For all gravity related tensile force calculations, true vertical depths should be used. • For casing, the as-cemented condition establishes the initial or base case on which all future service life load conditions are superimposed. After WOC, no further axial deformation from service life loads can be directly applied to the casing section below the TOC. It is generally assumed, however, that no rigid radial restraints exist on the casing below the TOC due to microannulus channelling or other void spaces. Therefore, additional axial forces from temperature and fluid density or pressure changes will act locally. For tubing, setting the packer establishes the initial or base case on which all future service life load conditions are superimposed. If the tubing is latched to the packer, then up to the capacity of the latch the tubing above the packer will behave as casing above the top of cement. If the tubing is not latched to the packer, additional axial loads and tubing movement must be considered. EPT Drilling
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• Massive lost circulation while running casing could result in additional tension due to loss of buoyancy. This is not a required normal design case but the need for designing against it should be considered for each well. • As seen frequently with drill string behavior, there will be a significant difference between the tension profile of the string for the case of picking up and for the case of slacking off. The same phenomena will also apply to casing and tubing. Effectively, friction will always oppose tubular movement. As a result, it will require a greater tension at surface (and all along the tubular string) to lift the tubular string than it will take to lower the tubular string. This frictional hysteresis effect may be seen readily on the weight indicator. In addition, the measured length of the string will be marginally longer when picking up than when slacking off. This phenomenon is usually ignored for casing design but can be important in tubing depth control, during tubing conveyed perforating, for example. “Buoyancy Factors” are acceptable for calculating the hook load but should not be used for any other part of tubular design.
10.2
Axial Force Components
For calculating the total axial force, Fa at any point during any service life load condition the following components must be considered: Fa = f (Fwt , Fbuoy , Fb , Fl , Fop , Fplug , Fbal , FT , Ff r , Fpkr ) ,
(10.3)
where: Fwt weight of the tubular in air below the point of interest (Equation 10.6) Fbuoy buoyancy force, calculated as an upward (compressive) force acting on the bottom of the tubular and a force on exposed shoulders in tapered strings (Equations 10.7 to 10.9) Fb additional tensile force from bending as a result of hole curvature, i.e., dogleg severity (Equation 10.10) Fl force (pull is positive, slackoff is negative), if any, imposed on landed casing/tubing after waiting for the cement/packer to set Fshock force arising from sudden accelerations and decelerations during running Fop overpull available for pulling the tubular if this becomes necessary during running operations Fplug tensile force created by the surface pressure used to bump the plug and/or pressure held during WOC (Equation 10.11) Fbal tensile force created from a change in external pressures external pressure or fluid density from the initial condition (Equation 10.14) FT tensile force created from a change in temperature from the initial condition (Equation 10.15) EPT Drilling
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Figure 10.1. Tubular in a Deviated Wellbore
Ff r tensile force created from fluid friction from high injection or production rates Fpkr piston load on expansion devices such as polished bore receptacles (Equation 10.32). The following sections describe the calculation procedure for each axial force component in Equation 10.3.
10.2.1
Fwt –Weight of Tubular in Air
The axial force created from the weight of the tubular is based on the TVD of the well. Figure 10.1 identifies the axial force components in a deviated wellbore which can be divided into two components: one acting parallel to the pipe axis and one acting perpendicular to the pipe axis. These components can be expressed as fwt = wa cos α,
(10.4)
N = wa sin α.
(10.5)
The component N is exerted by the wellbore and, with friction neglected, does not affect the axial force profile. Since cos α equals the change in vertical depth divided by the change in measured depth for the deviated hole section,
Fwt [lbf ] = wa [lb/ft] ∆z [ft TVD] ,
(10.6a)
Fwt [lbf ] = wa [lb/ft] ∆z [m TVD] × 3.281,
(10.6b)
or in Hybrid units,
or in SI units, EPT Drilling
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Figure 10.2. Buoyancy Effect on Axial Force
Fwt [N] = wa [kg/m] ∆z [m TVD] × 9.80665,
(10.6c)
where ∆z is the true vertical distance below the point of interest to the bottom of the string. For a tapered string, Equation 10.6 must be repeated for each separate section below the point of interest, with Fwt being the sum of the separate contributions.
10.2.2
Fbuoy –Buoyancy Effect
The impact of buoyancy on the tubular’s axial force profile is a compressive force acting across the bottom of the string. The compressive force is due to the hydrostatic pressure acting across the cross-sectional area of the tubular. Figure 10.2 identifies the pressure area for open-ended and close-ended tubulars. This treatment of buoyancy forces is adequate for casing whether vertical or inclined. It is not adequate for risers. For open ended tubulars, EPT Drilling
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Figure 10.3. Buoyancy Effect on Tapered Tubular String
Fbuoy = po (Ai − Ao ) ,
(10.7)
where the pressure is measured at the bottom of the tubular. For closed ended tubulars, Fbuoy = pi Ai − po Ao .
(10.8)
During running operations, provided the tubular is being completely filled with fluid of the same weight as that in the hole (annulus), pi = po , and Equations 10.7 and 10.8 produce the same result. For tapered strings (i.e., stepwise tapered), Fbuoy is calculated using the same pressure area approach as above. Figure 10.3 shows an example of Fbuoy for a tapered casing string. At the lower end, Fbuoy can be calculated with Equation 10.7 or 10.8, as appropriate. At depth x for the crossover, the Fbuoy is added to the axial force profile. Fbuoy
@ Depth x = po2 (Ao1 − Ao2 ) − pi2 (Ai1 − Ai2 ) ,
(10.9)
where po2 annulus pressure at depth x Ao2 area corresponding to casing OD of Section 2 = (π/4)D22 EPT Drilling
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Ao1 area corresponding to casing OD of Section 1 = (π/4)D12 pi2 pressure inside at depth x Ai2 area corresponding to casing ID of Section 2 = (π/4)d22 Ai1 area corresponding to casing ID of Section 1 = (π/4)d21 .
10.2.3
Fb –Tension Force from Bending
Bending as a result of hole curvature gives rise to tensile and compressive stresses. For the tension design check, the tensile bending stress is included in the tension calculation as an fictitious axial force which would produce a stress equal to the maximum bending stress in the cross section,
Fb [lbf ] = 64 c [◦ /100 ft] D [in] w [lb/ft] ,
(10.10a)
Fb [lbf ] = 64 c [◦ /30 m] D [in] w [lb/ft] ,
(10.10b)
Fb [N] = 7.53 c [◦ /30 m] D [mm] w [kg/m] .
(10.10c)
or in Hybrid units,
or in SI units,
The bending force only occurs where hole curvature exists, so the high Fb associated with build sections need not be applied to the whole length of casing. From the tensile design point of view this favors deep kick offs over shallow ones. In nominally straight sections a curvature of 1◦ /100 ft (1◦ /30 m) should be assumed for tension calculations unless local experience supports an alternative higher or lower value. For build sections DEA(E)64 results suggest a design curvature of target build rate +2◦ /100 ft (+2◦ /30 m). Connection ratings in tension may be in excess of the Fb which the connector can sustain without leaking. This is because bending may produce a net compression on one side of the pipe. For curvatures greater than 10◦ /100 ft (10◦ /30 m) consult Chapter 17.
10.2.4
Fplug –Surface Pressure to Bump Plug
Fplug refers to the tensile forces resulting from the surface pressure used to bump the cement plug and surface pressure held during WOC. Fplug for tubing is the pressure applied to set a hydraulically set packer. The tensile force is increased due to the pressure area calculation in Equation 10.11, under the assumption that the casing is free to elongate during the cementing operation. Fplug = piSurf Ai ,
(10.11)
where piSurf is either the surface pressure to bump the plug or the surface pressure held during WOC. EPT Drilling
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The latter Fplug is only built into the casing base case as cemented tension if the casing is landed and cement sets with that pressure present. In this case, when the pressure is released, negative ballooning (see Section 10.2.7) will generate an incremental compression as the internal pressure increases. The net result of this practice is Fplug = (1 − 2ν) piSurf Ai .
(10.12)
This is not a recommended practice, as a microannulus will be created following WOC when the surface pressure is released. Equation 10.12 also predicts the incremental tension induced in a tubing string when setting a hydraulically set packer.
10.2.5
Fl –Landing Force
Fl is a direct, incremental tension force imposed on landing casing after waiting on cement to set, or, in the casing of tubing, after the packer to which the tubing is latched has set. This is one method of preventing, or reducing the effects of, buckling and is discussed in more detail in Section 10.7 and Chapter 12. Fl is part of the initial, base case. Such tensioning (or slackoff) is usually not possible on a subsea well.
10.2.6
Fop –Overpull
Fop is the surface overpull available to assist retrieving a tubular if difficulties are encountered running it in the hole.
10.2.7
Fbal –Tensile Force from Change in Pressure or Fluid Density
The tensile effect of a change in external pressures external pressure or fluid density is shown in Figure 10.4 as ballooning. An increase in internal pressure increases circumferential strain, thus the tubular tends to contract axially due to the effect associated with Poisson’s ratio. Similarly, a reduction in internal pressure–reverse ballooning–tends to cause the tubular to elongate. Once the casing is cemented or the tubing packer is set, however, the tubular becomes fixed at the TOC/packer and wellhead and may not be free to contract or elongate. In this situation, changes in axial stress are proportional to the strain developed, provided that the tubular was landed with sufficient tension to prevent buckling (see Chapter 12), and that the tube’s yield strength is not exceeded. Fbal can be calculated directly from Equation 10.13. When pressure testing the casing after WOC or tubing after the packer into which it is latched is set, Fbal should be included in calculating the tensile forces. For a change in pressure which is the same along the whole uncemented length, e.g., a change in surface pressure, whether external pressures external, Fbal is calculated by Fbal = 2ν (∆pi Ai − ∆po Ao ) . EPT Drilling
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Figure 10.4. Ballooning Effects on Tension Forces
For changes in fluid density, e.g., increasing drilling fluid density when drilling ahead, the average pressure change over the uncemented length should be used, Fbal = 2ν (∆pi Ai − ∆po Ao ) ,
(10.14)
where ∆p can be correctly interpreted either as “change in average pressure” or “average change in pressure”. If buckling occurs, Equation 10.14 cannot be applied directly to determine the force. Section 12.2 should be used to determine if buckling occurs. Both ∆po and ∆pi depend on later activities, e.g., ∆pi might result from increasing drilling fluid density while drilling ahead, whereas any number of completion activities, including production, can alter the pressures to which a tubing string is exposed.
10.2.8
FT –Tensile Force from Change in Temperature
A change in temperature from the initial condition will increase or decrease the total axial force depending on the temperature change. FT can be calculated from Equation 10.15 and is superimposed to the base case axial force profile.
or in Hybrid units, EPT Drilling
FT [lbf ] = −αT [1/◦ F] E [psi] Ap in2 ∆T [◦ F] ,
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(10.15a)
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or in SI units,
FT [lbf ] = −αT [1/◦ C] E [psi] Ap in2 ∆T [◦ C] ,
(10.15b)
FT [MN] = −αT [1/◦ C] E [MPa] Ap mm2 ∆T [◦ C] .
(10.15c)
The product of the coefficient of thermal expansion for steel, 6.9 × 10−6 / [◦ F] and Young’s modulus (E = 30 × 106 psi) is approximately 200, if Equation 10.15 is expressed in US Customary units. Temperature assumptions for service life loads can be found in Chapter 14. Above top of cement, the average ∆T is used since the pipe can move to result in the same force everywhere. Below top of cement it cannot move axially, so the force depends on the local temperature. The possibility of temperature forces causing buckling is considered in Chapter 12. Both Fbal and FT are considered displacement type forces as they occur after the base case and tend to elongate or contract the tubular.
10.2.9
Ff r –Tensile Force Due to Fluid Friction
When fluid is pumped down the tubing or casing string at a high rate, fluid friction tends to lengthen the ∆p string. Likewise when fluid flows up the tubing, the string shortens. The fluid pressure drop ∆L can be determined using a suitable multiphase flow program or service company software. This force is most critical for tubing strings with high production rates or high volume water injection and is not normally significant for casing. If the tubing is free to move, Ff r =
∆p Ai L, ∆s
(10.16)
where L is the length below the point being considered for a production scenario or above the point being considered for a fluid injection scenario, and ∆p is assumed positive for flow up the pipe. Length change for the portion of tubing above the packer is calculated from Hooke’s Law,
∆Lf r =
∆p ∆s
L2p Ai
2EAp
.
(10.17)
If tubing is fixed to a packer, Ff r = −
∆p ∆s
Lp Ai L − , 2
(10.18)
where L is the completion length. For casing, the effect of fluid friction is seldom of any significance and is usually ignored in design. For tubing though, the effect on motion in PBRs, for example, and thus required seal lengths, should be considered for high rate wells. EPT Drilling
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10.2.10
Fshock –Shock Loads
Fshock is the axial force resulting from shock loads when: • Sudden deceleration forces are applied. • The tubular string is picked up off of the slips. • Slips are “kicked in” while pipe is moving. • Casing hits a bridge or jumps off a ledge downhole. An instantaneous velocity of 5 ft/s (1.5 m/s) is suggested for the shock loading. The velocity assumed for Fshock during design should not be exceeded during rig casing running operations. Fshock can be calculated from
or in Hybrid units,
or in SI units,
10.2.11
Fb [lbf ] = 1, 780v [ft/s] Ap in2 ,
(10.19a)
Fb [lbf ] = 5, 840v [m/s] Ap in2 ,
(10.19b)
Fb [N] = 40.3v [m/s] Ap mm2 .
(10.19c)
Fpkr - Packer Force
For tubing it is useful to distinguish the buoyancy force (Section 10.2.2) at the lower end because of the unique calculation problems associated with the packer (see discussion in Section 10.6.1). Otherwise, Fpkr is identical in principle and application to Fbuoy .
10.3
Installation Tensile Force Calculations
For installation tensile force calculations, the following service life load conditions have to be evaluated: • Running casing or tubing • Cementing casing. EPT Drilling
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10.3.1
Running Casing or Tubing
For running operations the design requirements for shock loading, overpull and bumping the cement plug are, respectively: Fa = Fwt + Fbuoy + Fb + Fshock ,
Fa = Fwt + Fbuoy + Fb + Fop ,
DFt ≥ 1.4 casing, 1.33 tubing,
(10.20)
DFt ≥ 1.4 casing, 1.33 tubing,
Fa = Fwt + Fbuoy + Fb + Fplug ,
(10.21)
DFt ≥ 1.4 casing, 1.33 tubing,
(10.22)
where Fshock is assumed constant along the string, and Fwt decreases as depth increases. When using Equation 10.22 in tubing design, the expression 10.12 should be used, as it models the tension in the string prior to release of pressure after the hydraulically set packer is set. One use of Equation 10.21 is to assess the available Fop by setting Fa equal to the tensile rating/1.4. If Fop is less than 100 kips a more detailed study of Fop requirements should be considered. Operational procedures can be used to control the Fshock impact on the string design. The Fshock and Fop design check can often be critical for casing with special clearance connections, and rig operations must be notified of running speed limitations.
10.3.2
Cementing Casing
Two conditions should be considered, (a) that with spacer and cement inside the casing, Fwt = air weight of casing,
(10.23)
Fbuoy = outside area of casing x hydrostatic pressure of mud column outside casing – casing inside area x hydrostatic pressure of (mud + spacer + cement), Fplug = surface pressure if any for cement displacement x casing inside area.
(10.24)
(10.25)
and (b) that with spacer and cement outside the casing, Fwt = air weight of casing,
Fbuoy = outside area of casing x hydrostatic pressure of (cement + spacer + mud) – casing inside area pressure of mud column inside casing, Fplug = surface pressure used to bump the plug x casing inside area. EPT Drilling
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(10.27)
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10.4
Initial Conditions (Base Case)
The as-cemented base case on which all other casing service life loads are superimposed is Fai = Fwt + Fbuoy + Fb + Fplug + Fl ,
DFt ≥ 1.4,
(10.29)
where, for casing, Fwt and Fbuoy are as for case (b) in Section 10.3.2. Fplug is that arising from any surface pressure held throughout waiting on cement and landing casing and is given by Equation 10.12. Fl is any additional tension or compression imposed on landing casing after waiting on cement. Once the cement is cured and the casing landed in the wellhead, the casing is treated in “single string” analysis as rigidly fixed axially at the wellhead and at the top of cement. For tubing, the initial condition is defined by Fai = Fwt + Fbuoy + Fb + Fplug + Fl ,
DFt ≥ 1.33.
(10.30)
Fbuoy is usually calculated by Equation 10.7 using the completion fluid density, and taking due account of proper cross-sectional areas as discussed in Section 10.6.1. For hydraulically set packers, Fplug is calculated with Equation 10.12. Fl is not applicable to packers or other expansion devices permitting tubing movement.
10.5
Drilling and Production Tensile Force Calculations
For all drilling and production service life loads the tension design must calculate the changes from the as-cemented initial condition caused by later temperature, pressure or flow changes1 . Fa = Fai + Fbal + FT + Ff r + ∆Fpkr ,
DFt ≥ 1.4 casing, 1.33 tubing,
(10.31)
where ∆Fpkr applies only to tubing. The burst and collapse sections should be consulted for pressure loadings which will give rise to ballooning forces. Multiple string analysis considers the effects of the small movement of the wellhead up or down as later strings are run and production forces imposed. Multi-string analysis is necessary for calculating wellhead movement and tieback pretensions and can help demonstrate acceptability of designs that are borderline using single string analysis. Multi-string analysis is best done using a suitable program, e.g., WellCat.
10.6
Tubing Tensile Design
Virtually all of the considerations given above will apply for completions and tubing, the primary difference being that tubing is constrained (if at all) at its lower end by a packer, rather than cement. Also, in addition to the buoyancy force on plugs or crossovers, there will be pressure loads on any expansion devices. Axial loads in tubing involve complex interactions and it is not always easy to determine a priori which load case will generate the worst conditions. Axial compression is also significant in many load cases and 1 Here,
we include the landing force in the calculation of Fai . One could argue that Fl occurs after the “initial condition” and should be categorized as a service life load. If so, then Fl should be removed from Equations 10.29 and 10.30 and added to all occurrences of Equation 10.31
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may be exacerbated by buckling and the presence of expansion devices. Buckling analysis is a fundamental requirement for all tubing (Chapter 12). The connection will play a significant role in determining whether the compression that results is acceptable.
10.6.1
Expansion Devices
Where expansion devices are used, pressures will still act on any exposed areas. When there is a higher internal pressure than external, this pressure will generate an upward force on the tubing above the expansion device and a downward force on the tubing beneath the expansion device. The force acting on the upper tubing is given by Fpkr = po (Ab − Ao ) − pi (Ab − Ai ) .
(10.32)
The critical component to be identified is the seal bore area, Ab (Figure 10.5). Ab is the area dimension of the parts that move relative to each other: • For an expansion joint this is normally the outside diameter of the pin member, as the seals are normally on the coupling/box member. • For a PBR, this is normally be the inside diameter of the coupling/box member, as the seals are usually on the pin member. Apart from this subtle difference, PBRs and expansion joints are treated identically. It is usual to position expansion devices above packers and indeed in most commercial stress analysis programs (including Wellcat) the expansion joint is always assumed to be at the packer itself. The same analysis can be used with any device which joins two sections of tubing even if no relative movement is possible. Anchor latches and pinned expansion devices have a seal bore and a shear release device (shear ring, pins, screws etc.) between the two parts. The force acting on the release mechanism due to the pressure at the device is calculated with Equation 10.32. For example a 5.5 in. 17 lb/ft tubing string has an expansion joint with a seal bore of 6 in. A 9,000 psi internal pressure and a 4,000 psi external pressure generate an axial force on the upper tubing of π 2 π 6 − 5.52 − 9, 000 62 − 4.8922 = 67, 242, (10.33) 4 4 which is a compressive force of 67,242 lbs. If this were an anchor latch above a packer, then the anchor would have to be pinned above this value. Fpkr = 4, 000
10.6.2
Tubing Load Cases for Axial Loads
It is not usually possible to determine exactly which load cases are worst case beforehand. It is useful, therefore, to examine all load cases that could be extremes. This involves looking at possible combinations of pressures and temperatures. Because of the complexity of tubing plugs and expansion devices, the worst case tension is not always cold conditions and high pressures, and the worst case compression is not always hot conditions and low pressures. A full examination of all potential load cases is encouraged. A full list of potential load cases is given in section 12. EPT Drilling
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Figure 10.5. Polished Bore Receptacles and Expansion Joints
Table 10.1. Example of Possible Tubing Axial Load Cases
Hot
Burst
Cold
Hot shut-in. Possibly some injection cases
Tubing test or injection/stimulation.
especially if injection immediately precedes production or the injection fluid is hot. Collapse
Evacuated tubing, hot and full MAASP on “A” annulus. Alternatively maximum
Annulus test or evacuated tubing, cold and full MAASP on “A” annulus.
drawdown production and full “A” annulus MAASP.
10.6.3
Length Changes
Tubing and completions have one unusual feature that is not normally present with casing - tubing movement. Examples of tubing movement include: • The use of expansion devices (as covered above); • Installation loads such as pressure tests when the tubing/packer has not been set. In these circumstances the tubing is free to move. EPT Drilling
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For simple single string designs with only one size and weight of tubing, tubing movement can be determined by calculating the axial force and then using Hooke’s law to derive a length change, ∆L =
L∆Fa , E (Ao − Ai )
(10.34)
where ∆Fa is the change in axial force from the initial condition, usually the point at which the completion is landed. Thus the only forces that should be considered are change in forces. Examples would be changes in ballooning, buoyancy, thermal loads or fluid friction. If movements are possible, they will also change the load distribution. In some cases the movement will replace a force. If movement is allowed, the ballooning force will be replaced by an equivalent movement. The forces that follow this behavior are ballooning and thermal. Other forces, specifically piston forces or buoyancy changes, will generate both a force and a length change. In fact, these two effects can only generate a force if there is movement. While the total movement can be calculated from summing the length changes from the individual forces, the same approach can be applied to combination strings such as completions involving tapers or changes in weight. A buoyancy force will be generated at each crossover. Implications of length changes include: • Seal bore length - the seal bore and seal stack of the PBR or expansion joint must be able to accommodate the total tubing movement. Worst cases are normally those involving cold injection and high pressures. Stimulation or water injection are often severe examples. • Setting of hydraulic set packers. Hydraulic set packers move when being set. Much of this movement comes from the piston force applied to a plug prior to the slips engaging. This will be partially offset by ballooning. If this length change is large, it is possible that the tubing will bottom out. This is a particular risk where a no-go or other locator is used to space out the packer. If the tubing is prevented from moving down during the application of the setting pressure, certain packers (”mandrel movement packers”) will not set. • Seal reliability - continuous movement of seals within a polished bore are detrimental to seal life. Where possible movement should be limited. For example, it might be possible to set up the completion such that there is only movement during a high pressure stimulation. This is achieved by limiting the downward movement of the tubing by spacing out the expansion device to be closed when run.
10.7
Tensile Force Check for Buckling Analysis Requirements
After calculating Fa for drilling and production load cases, the tubular should be checked for helical buckling if any of the following occur: • An increase in drilling fluid density occurs internal to the tubular; • A decrease in drilling fluid density occurs external to the tubular; • A pressure increase occurs internal to the tubular; EPT Drilling
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• A temperature increase occurs. If, during the installation load, casing is set on bottom with additional slack-off weight, the casing should be checked for helical buckling. For helical buckling calculations, refer to Chapter 12.
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Chapter 11
Triaxial Design Analysis 11.1
Triaxial Design Statement
Triaxial analysis is required. Landmark tubular design products licensed to BP (StressCheck, WellCat and portions of WellPlan) perform triaxial stress checks, so no extra user effort is involved. The primary purpose of the triaxial design factor is to avoid local yielding, particularly during: 1. Casing buckling above top of cement; 2. Casing landing on bottom; 3. Compression in tubing above packers during production; 4. Compression above expansion devices with high internal pressure. The governing criterion for burst is the API uniaxial internal yield criterion (Barlow’s relation), which must be satisfied regardless of the triaxial design factor. The triaxial design factor, however, remains a most useful single factor highlighting load combinations approaching yield.
11.2
Von Mises Equivalent (VME) Stress
Service loads on oilfield tubulars (e.g., axial tension or compression, internal and external pressures, bending) generate triaxial stresses rather than the uniaxial or biaxial stresses assumed in many API load capacity equations. The three principal stresses for casing and tubing design are axial (plus bending), σa + σb , radial (σr ), and circumferential or hoop (σh ), as shown in Figure 11.1. The recommended theory for calculating triaxial stresses is known as the Hencky-von Mises theory. The von Mises theory consists of defining an equivalent stress (σe ) in the following manner and then relating that stress to the specified minimum yield stress (fymn ) of the tube, σe = [σr2 + σh2 + (σa + σb )2 − σr σh − σh (σa + σb ) − (σa + σb )σr ]1/2 . EPT Drilling
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Figure 11.1. Principal Stresses
Other than unusual applications such as liner drilling, torsional stresses are normally negligible in tubular design after installation. The triaxial stress design factor is defined as DFv =
fymn . σe
(11.2)
According to the von Mises theory, an axial tensile stress can increase the circumferential stress capacity before first yield of the tube body and vice versa. This phenomenon is depicted in Figure 11.2, a diagram similar to those produced by many tubular analysis programs. The locations of the various bounding curves in the figure depend on the design factors and allowable wear, so this figure is for illustrative purposes only. The calculation of Formula 11.1 is required at the top and bottom of each string interval of a single weight and grade and at each particular point of interest, as follows: • A change in tube weight, grade or outside diameter; • A specific change in external pressure at a particular depth; • A specific change in internal pressure at a particular depth; • Top of cement, packer, plug or expansion device; • Specific hole geometry–doglegs, washouts, change in external casing size (for buckling). The triaxial load capacity diagram used in software such as StressCheck and WellCat is normalized to allow a 2-D plot of triaxial stress and is not used directly for analysis calculations. The diagram does provide, however, a picture of the triaxial stress ellipse as compared to the current API rating window for a typical EPT Drilling
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Figure 11.2. Triaxial Load Capacity Diagram
tube. As shown in the compression/internal pressure quadrant, the API burst rating can exceed the triaxial stress allowable of the tube, and if so, the triaxial criterion will govern the design. For the tension/internal pressure quadrant, the triaxial stress allowable may exceed the uniaxial burst. Here the latter will govern the design. Note also that these plots are normally for a specific yield of pipe, and therefore the effects of temperature dependent yield are usually not included. The collapse region of the diagram is more difficult to apply to all tubulars because collapse is both a stability and yield phenomenon. In general, both API and triaxial design factors should be satisfied. A satisfactory triaxial design factor does not necessarily mean a satisfactory collapse design. Elastic instability is an increasingly significant contribution to collapse as D/t increases, and triaxial analysis becomes irrelevant and unconservative in relation to collapse for D/t greater than approximately 15. It is necessary to satisfy both the triaxial stress versus yield and API uniaxial collapse requirements.
11.3
Triaxial Calculation
To calculate σe , σa and σr and σh are required.
11.3.1
Total Axial Stress Calculations
Axial loads are calculated as in Chapter 10 except that the bending stresses are not converted to equivalent tensions, σa =
Fa , Ap
σb = σhb + σdev . EPT Drilling
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Both σhb and σdev (Chapter 12) are local axial stresses, i.e., they vary over the length of the string.
11.3.2
Radial and Circumferential Stress Calculation
The inner and outer radial and circumferential stresses are calculated from the Lame´equations for thick walled cylinders. The radial stress is calculated by (p −po )d2wall D2 4r 2
(pi d2wall − po D2 ) − i σr = D2 − d2wall
.
(11.5)
Note dwall corresponds to the minimum permissible local API wall thickness, i.e., the API specified wall thickness reduced by some fabrication tolerance, usually taken as 12-1/2%. For the inside diameter stress check (r = dwall /2), the equation reduces to σri = −pi ,
(11.6)
and for the outside diameter stress check (r = D/2)
σro = −po .
(11.7)
The circumferential stress is calculated by (p −po )d2wall D2 4r 2
(pi d2wall − po D2 ) + i σh = D2 − d2wall
.
(11.8)
For the inside diameter stress check, this reduces to
σhi =
pi (D2 + d2wall ) − 2po D2 , D2 − d2wall
(11.9)
2pi d2wall − po (D2 + d2wall ) . D2 − d2wall
(11.10)
and for the outside diameter
σho =
In the absence of bending, the peak VME stress always occurs at the pipe inside diameter. If bending due to buckling or specific doglegs occurs, the peak VME stress can occur on the pipe inside diameter or outside diameter surface as shown in Figure 11.3. One calculation is needed if there is no bending; four calculations are needed (using maximum and minimum axial stress at both outside diameter and inside diameter) if bending is present. Bending stresses are added to the total axial stress for VME calculation. Refer to Chapter 12 for bending stress calculations. EPT Drilling
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Figure 11.3. Locations for von Mises Stress Calculations with Bending
11.3.3
Triaxial Stress Safety Factor Calculation
Substitute σa + σb , σr , and σh into Formula 11.1 to calculate σe . Then substitute σe into Formula 11.2 to calculate the corresponding VME safety factor for the particular service life design load. The safety factor must meet the minimum triaxial design factor for the appropriate tubular type and service life load. For all tubulars, the minimum acceptable safety factor is 1.25.
11.4
Example Problem
At a certain depth in a well, the 177.8 mm, 43.16 kg/m (7 in, 29 lb/ft), N80 casing is subjected to an internal pressure of 15 MPa (2176 psi), an external pressure of 6 MPa (870 psi), and an axial force of 444,822 N (100,000 lb). The tube is being run through a portion of the well having a dogleg of 10˚/30 m (10.16˚/100 ft). The manufacturing tolerance for wall thickness is 12.5%. Compute the triaxial safety factor. The calculations are summarized in Table 11.1. Since the bending stress is non-zero, four calculations must be made (inner and outer radius, positive and negative bending stress). In the absence of bending, the von Mises equivalent stress, σe will always be largest at the inner radius. The σa component of the axial stress can be given in a variety of ways. Here, we assume it is available from some other, related calculation. The design factor is obtained using the maximum of the computed effective stresses. In this example, the maximum stress occurs at the outer radius on the tensile side of the bend.
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Table 11.1. Triaxial Stress Example Calculation Action
Variable
Metric
US Traditional
Input variables
pi
15 MPa
2,176 psi
d
78.54 mm
6.184 in
po
6 MPa
870 psi
D
177.8 mm
7.000 in
dwall
159.67 mm
6.286 in
Compute curvature
c
5.818 x 10-3 rad/m
1.773 x 10-3 rad/ft
Compute stresses at
σr
-15.0 MPa
-2,176 psi
σh
78.0 MPa
11,316 psi
σa
81.6 MPa
11,835 psi
σdev
± 96.0 MPa
± 13,707 psi
σr
-6.0 MPa
-870 psi
σh
69.0 MPa
10,010 psi
σa
81.6 MPa
11,835 psi
σdev
± 108.7 MPa
± 15,516 psi
σe +
166.9 MPa
24,008 psi
σe -
92.8 MPa
13,343 psi
σe +
171.6 MPa
24,653 psi
σe -
87.5 MPa
12,524 psi
Adjust wall thickness (inside diameter) for calculating σr and σh
dwall
Compute stresses at D
Compute VME stress at dwall
Compute VME stress at D
Compute triaxial design
DFv
3.25
factor
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Chapter 12
Buckling and Compression Design Considerations 12.1
Buckling Design Considerations
For a fully cemented casing, consideration of burst, collapse and axial forces resulting from buoyancy, weight, ballooning and temperature change applied to the pipe body and connections will normally suffice to produce an adequate design. There remains, however, an additional phenomenon which must be considered–buckling in unsupported intervals of casing and almost all tubing1 . Buckling of casing or tubing2 is a form of elastic instability. In the case of a column in a building, buckling is associated with large lateral displacements and failure. For casing and tubing the displacement is limited by the confining hole –either the previous casing string or open hole–so the total radial deflection is equal to the casing-to-confining hole clearance, and the buckled string shape at large enough compressive loads is that of a helix. In many cases the restraint afforded by the hole means that buckling of a tubular will not actually result in either yield or failure. However, considering buckling is important because of the following associated issues: • In uncemented intervals opposite long washouts, or an oversize rathole, conditions can arise where the lateral deflection accompanying buckling can be sufficient to fail a casing string. • Buckling of casing or tubing can result in an inability to pass tools through the buckled interval. • Drilling ahead through buckled casing can result in high casing wear. This effect is particularly notable in deeper wells because of drilling fluid density and circulating temperature changes. • Drilling ahead through uncemented buckled casing can result in connection failure near the neutral point of the buckled string. 1 An
exception would be the tubing/casing in a tubingless completion where the tubing/casing has been cemented to surface.
2 Here
we refer exclusively to column buckling. Another form of instability, cross-sectional buckling of a tubular cross section due to external pressure, is covered in Chapter 8.
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Table 12.1. Column Buckling Criterion Criterion
Meaning
State of Tubular
Fe > Fcr
Unstable
Tubular is buckled
Fe = Fcr
Neutral Stability
Tubular is on the verge of buckling
Fe < Fcr
Stable
Tubular is not buckled
• Under appropriate circumstances, and particularly in the case of drill ahead through an intermediate casing string, the small torsion associated with the helical post-buckled shape can unscrew a threaded connection. • Buckled tubing can undergo significant axial movement and/or interaction forces, particularly at the lower end of the string. Movement of tubing is important in considering polished bore receptacles (PBRs) (refer to Completion Design Manual for details). • Excessive buckling can result in localized strain concentrations (wrinkling) causing failure on subsequent tensile loading. Buckling (and bending) of casing and tubing is slightly more complicated than for structural columns because of the effects of internal and external pressure. Internal pressure exerts a lateral force away from the center of curvature and so tends to encourage buckling. External pressure exerts a force towards the center of curvature and so tends to discourage buckling. While these forces are lateral their effect can be calculated by introducing a fictitious or effective tension Fe related to pressures and the actual physical tension. This effective tension is of relevance only as an aid to buckling and bending calculations and should not be used in calculating an axial tension design factor.
12.2
Effective Tension
To determine if buckling will occur, one must first calculate the effective tension, Fe , at the uncemented point of interest. If the effective tension is greater than3 a critical buckling value, Fc , then buckling will not occur. If the effective tension is less than the critical buckling value then buckling will occur. The criterion for buckling is summarized in Table 12.1. This criterion is to be applied at every depth in the unsupported portion of the tubular. It is possible for a portion of a tubular to be buckled, while another portion of the tubular is straight. For a vertical wellbore, Section 12.2.2 demonstrates that Fcr = 0, and instability, neutral stability and stability are determined by whether the effective tension is negative, zero or positive, respectively. For an inclined or curved wellbore, Fcr 6= 0 and the effect of the wellbore trajectory must be taken into account. 3 The
terms “greater than” and “less than” used here are to be viewed in an algebraic sense. That is, a small negative number is “greater than” a large negative number.
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Table 12.2. Effective Tension Example Calculation Action
Variable
Metric
US Customary
Input variables
Fa
0.03 MN
6744 lb
pi
35 MPa
5076 psi
po
2.5 MPa
362.6 psi
D
73.03 mm
2.875 in.
t
5.51 mm
0.217 in.
Ai
3019.1 mm2
4.680 in2
Ao
4188.8 mm2
6.492 in2
Fe
-0.0652 MN
-14,658 lb
Compute areas
Compute effective tension
The effective tension is related to the true tension by [52] Fe = Fa − (pi Ai − po Ao ).
(12.1)
The neutral point is the string axial location corresponding to neutral stability. Comparing Equation 12.1 with the buckling criterion in Table 12.1, the neutral point may correspond to an axial location that is in actual tension or compression, depending on the values of the internal and external pressure. In general, the neutral point is not the axial location corresponding to a transition from actual axial tension to actual axial compression. A key aspect of effective tension is that the tube does not have to be in physical compression (as would be measured by a strain gauge) to buckle, as shown by the following example:
12.2.1
Example Problem - Effective Tension
At a depth of 3000 m (9842.5 ft) in a wellbore the internal pressure is 35 MPa (5076 psi), the external pressure is 7.5 MPa (1088 psi) and the axial force is 0.03 MN (6744 lb). The tube is 73.03 mm, 9.67 kg/m (2.875 in. 6.5 lb/ft) with a wall thickness of 5.515 mm (0.217 in.). Compute the effective tension. The procedure is summarized in Table 12.2. The actual physical tension is 6,744 lb, yet the effective tension is -14,658 lb, i.e., negative, so in a vertical wellbore the tube will buckle. Therefore, the main items of interest in buckling are contributors to effective tension: • Increase in internal pressure from increased fluid density or increased surface pressure promotes buckling; • Reduction in external pressure from density reduction or loss of fluid; • Compressive axial loads promote buckling; EPT Drilling
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• Temperature increase from drilling or production promotes buckling.
12.2.2
Buckling in a Vertical Wellbore
In a straight, vertical wellbore, for an initially straight, weightless tube the critical buckling load is given by the Euler buckling formula [91], EI , (12.2) L2 where k varies with the conditions at either end of the tube. The largest value of k corresponds to both ends of the tube being fixed such that neither lateral displacement nor rotation is permitted, k = 4. In Fcr = −kπ 2
practical terms the critical buckling load is very small for a long tube. Consider the previous example problem involving 3000 m (9842.5 ft) of 73.03 mm (2.875 in.) tubing. For this string, assuming both ends to be fixed, Fcr = 0.62N (0.14lb). In vertical wells this means that for practical purposes Fcr = 0 and buckling of an uncemented string will occur if Fe < 0.
12.2.3
Buckling in an Inclined Wellbore
In a vertical well the effective force necessary to buckle a tube of any reasonable length is nil. With increasing inclination, however, the tube gravitates to the low side of the wellbore under its own weight. This tendency to lie on the low side of the hole means that additional compression is needed for the pipe to laterally climb the hole wall away from the low point. Buckling in an inclined hole occurs in two stages. First, the tube buckles into a snakey or sinusoidal shape that conforms to the lower portion of the confining hole. The critical force necessary to initiate sinusoidal buckling in a straight, inclined confining hole was derived by Dawson and Paslay [29], Fcr = −
r
4EIwe sin α , rc
(12.3)
where the effective weight per length, we , is the gradient of the effective tension4 and is given by we = wa + (γi Ai − γo Ao ).
(12.4)
For a vertical wellbore α = 0, and Fcr = 0, as before. With continued load increase, a sinusoidally buckled tube will continue to deform and eventually assume the form of a helix5 . This transition occurs at a critical load of approximately twice the magnitude of that given in Equation 12.3 for the initiation of sinusoidal buckling [42]. Further loading tightens the pitch of the helix and increases the wall contact force. In an inclined wellbore, buckling will occur if Fe < Fcr (i.e. the effective tension has to be more negative than the critical buckling force which is itself negative) as indicated in Table 12.1. In tubular design in 4 The effective weight has the same relation to effective tension as the air weight has to actual or true tension. In a vertical wellbore, as one proceeds up the tubular, the effective (air) weight per length is the rate of change of effective (true) tension. 5 For
a vertical wellbore, the transition from sinusoidal buckling to helical buckling occurs instantaneously. The tube first buckles two-dimensionally into a sinusoid, but almost immediately contacts the confining hole. At that point the post-buckled shape becomes three-dimensional (helical). In an inclined wellbore, there is a definite transition from sinusoidal to helical buckling, with sinusoidal buckling representing a distinct phase in the progression of increasing buckling severity.
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inclined wells it is usually assumed that if Fe < Fcr then the stresses arising can be conservatively treated by assuming that a helix has developed, as in a vertical wellbore.
12.2.4
Buckling in a Curved Wellbore
The solution for a curved wellbore has been proposed by He and Kyllingstad [39] Fcr = − where
r
4EIN , rc
(12.5)
r
dβ 2 dα ) + (we sinα − Fe )2 . (12.6) ds ds In the special case of a straight, inclined wellbore, Equations 12.5 and 12.6 reduce to 12.3, since for this N=
(Fe sinα
situation the normal force per length, N , is given by we sinα. Increasing N increases the (negative) value of Fcr , and, therefore, increases the effective compression required to buckle the target tubular. The following conclusions are evident from Equations 12.5 and 12.6: • A nonzero turn rate (dβ/ds) makes buckling more difficult. • A positive build rate (dα/ds > 0) makes buckling more difficult (recall Fe must be negative or buckling is not an issue). • A negative build rate (e.g., positive drop rate) makes buckling more or less difficult, depending on whether weight or hole curvature dominates the second term in the radical of Equation 12.6. Finally, note that for a weightless tube, Equation 12.6 becomes r
dβ 2 dα ) + ( )2 = Fe c, (12.7) ds ds that is, the normal force per length is just the product of the effective force and the dogleg severity, emphasizing the importance of hole curvature in mitigating buckling. Of course, hole curvature also has offsetting, N = Fe
(sinα
undesirable consequences, which must be duly weighed in the overall well design discussion.
12.3
Permanent Corkscrewing (Yield)
Permanent corkscrewing refers to extreme cases of helical buckling when the combination of axial, radial, circumferential, and particularly bending stresses accompanying buckling are so severe that the tube body yields. Once the tube has yielded, subsequent unloading will not completely eliminate all deformation and the tube will have permanent, helical curvature (see Figure 12.1). In extreme cases local, i.e. over a few inches, instability of the pipe wall may result which is manifested as a wrinkle. In this condition the pipe body may still contain pressure while under compression, but will probably fail catastrophically on application of tension during some subsequent operation. At particular risk in this regard are tubulars with a stiff upper part (e.g., 10-3/4) and a less stiff lower part (e.g., 9-5/8), where, say two or three lengths of the 9-5/8 are above the top of cement. In these circumstances most of the buckling can be concentrated in the 9-5/8 EPT Drilling
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Figure 12.1. Photograph of Permanently Corkscrewed Tubing
rather than being distributed over the whole string. A similar situation would be a cross-over from 5-1/2 to 4-1/2 tubing in the lower portion of a tubing string in order to accommodate the dimensions of a production liner. The use of design software such as StressCheck or Wellcat is recommended. The bending stress resulting from helical buckling may be calculated as follows for a tube of one diameter and weight:
1. The pitch is the distance between spirals on the helix (Figure 12.1) and is approximately calculated from EPT Drilling
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P =π
r
8EI . Fe
(12.8)
2. The radius of curvature of the helix is
Rc =
P 2 + 4π 2 rc2 . 4π 2 rc
(12.9)
If the radius of curvature calculated in Equation 12.9 is expressed in inches, the equivalent curvature or dogleg severity (DLS) in degrees per 100 ft is
c=
5, 730 . Rc /12
(12.10)
For casing that will be drilled through for an extended time, the dogleg severity should be maintained below 2◦ /100 ft. 3. The axial stresses due to bending as the tube assumes a helical shape are calculated from Equation 12.11. Bending creates axial tensile stresses on one side of the casing and axial compression on the opposite side.
σhb = ±Erc,
(12.11)
where r is the pipe radius where the stress is calculated. The maximum bending stress occurs at the outer surface of the casing, i.e. at r = D/2. However, when there is a combined pressure/bending loading, both inside and outside surfaces should be checked for triaxial stress–a total of four points of investigation as described in Chapter 11. The triaxial design factor is intended to prevent excessive stresses resulting in corkscrewing or wrinkling. It is usually advisable to minimize helical buckling: • The dogleg severity and pitch of the helix can create drilling problems especially in washed out hole sections. The increased dogleg severity will promote casing wear and the pitch of the helix may restrict the free passage of downhole tools, while bending stress may also affect connection choice (see Chapter 17). • Helical buckling acts like a shortening of the tubing in calculating packer seal requirements and forces. However, it is not necessarily essential to eliminate helical buckling. For example an uncemented production casing will frequently buckle in the case of a tubing leak, as will tubing during high temperature production. Provided situations such as these are considered in the tube design and connection selection they may be acceptable. An additional issue related to the post buckled shape is whether a buckled casing can pass a particular tool diameter. This is considered in Section 12.3.1. EPT Drilling
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12.3.1
Tool Free Passage Length
To calculate the free passage length of specific diameter tools, Ltool =
P d − Dtool cos−1 [1 − ], π rc + d/2
(12.12)
where Ltool is the rigid length of a tool that can pass through the buckled tubular, ignoring both friction and possible deformation of either the tool or the tubular and cos−1 [...] is expressed in radians, not degrees. The free length value can be used as a guide to determine potential problems for drifting tools. As neither tools nor casing are completely rigid, the free length value calculated by Equation 12.12 will be conservative. Free length tool drifts less than 3 m (10 ft) should be a flag for potential problems. Field experience should be used to establish the base guidelines for tool length drifts.
12.3.2
Reduction of Helical Buckling
If helical buckling is determined to be a problem, the following steps can be considered, either separately or in combination, to reduce its severity: • An additional tension load (overpull) can be applied after WOC (casing) or after setting the packer (tubing), depending on wellhead and slip details. • For casing, changing the cement top (often, but not always, raising it) may help. However, moving the TOC to preclude buckling may not be operationally feasible. Therefore, a compromise between TOC and overpull may be needed to reduce buckling. • For certain tubing operations, it may be possible to apply external pressure during the operation to minimize helical buckling. • For tubing, switching from an unlatched to latched packer condition can induce enough true axial tension to eliminate or mitigate helical buckling. Of course, other considerations will also affect the decision to latch the tubing to the packer (for example, induced packer-to-casing force). • A tension can be induced in casing by holding internal pressure while waiting on cement after landing. This option is not recommended, as releasing the pressure after WOC will introduce a microannulus at the casing/cement interface. With the wide availability of appropriate software, manual calculation of helical buckling and its effects is not appropriate. The following example is intended for education rather than use.
12.3.3
Example Buckling Problem
A 13,000 ft. string of 244.5 mm, (9-5/8 in. 47 lb/ft) P110 Buttress casing was run in a 355.6 mm (14 in.) hole in 12 ppg mud and cemented with 3000 ft. of 15.8 ppg slurry. The plug was bumped with 12 ppg mud. Determine if the casing will buckle while drilling ahead to 17,500 ft. with a 15 ppg mud and an average temperature increase of 50◦ F. Buckling can be reduced in this example by: EPT Drilling
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Table 12.3. Buckling Example Calculation Action
Variable
Metric
US Customary
For 9-5/8 casing
D
244.5 mm
9.625 in.
d
220.5 mm
8.681 in.
Ao
46,951 mm2
72.76 in2 59.19 in2
Ai
38,186 mm2
Ap
8,765 mm2
13.57 in2
I
5.938 x 107 mm4
142.51 in4
rc
55.55 mm
2.1875 in.
As Cemented Pressure at shoea
pi
55.87 MPa
8,104 psi
po
59.96 MPa
8,696 psi
pi
42.98 MPa
6,234 psi
po
42.98 MPa
6,234 psi
pi
0 MPa
0 psi
po
0 MPa
0 psi
At shoeb
-680,923 N
-153,078 lb
Pressure at TOCa
Pressure at surfacea
Axial force (Fa )
Effective force (Fa )e
At TOCc
-53,724 N
-12,078 lb
At surfaced
2,036,939 N
457,922 lb
At shoe
0N
0 lb
At TOC
322,625 N
72,529 lb
2,036,939 N
457,922 lb
At surface Conclusion
Effective force is everywhere ¿ 0, no buckling. Drill Ahead, drilling fluid density increases to 15 ppg, ∆T = 50◦ F
Pressure at shoea
pi
69.84 MPa
10,130 psi
po
59.96 MPa
8,696 psi
pi
53.73 MPa
7,792 psi
po
42.98 MPa
6,234 psi
pi
0 MPa
0 psi
po
0 MPa
0 psi
At TOCc
-555,492 N
-124,880 lb
At surfaced
1,535,171 N
345,120 lb
At TOC
-589,446 N
-132,513 lb
1,535,171 N
345,120 lb
Pressure at TOCa
Pressure at surfacea
Axial force (Fa )f,g
Effective force (Fa )e
At surface Conclusion
Effective force is everywhere < 0 at cement top, implying buckling.
a Using conversion factor 0.051948 psi/ft-ppg. b = p A − p A evaluated at shoe depth. o o i i c = F evaluated at shoe depth + air weight of casing to TOC. a d = F evaluated at shoe depth + air weight of casing to surface. a e = F − p A − p A evaluated at current depth. a o o i i f Includes ballooning force = 2ν ∆p A − ∆p A . o o i i g Includes temperature force = −α A ∆T . T p
• Increasing the top of cement to around 7000 ft. However, this may increase lost circulation and cost of cement. If this approach is considered, the initial (as cemented) axial force at the bottom of the string will be increased due to added cement and the buckling calculations should be repeated. • Additional tension, in the form of overpull, can be applied after WOC and prior to setting the slips. EPT Drilling
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In this example, a vertical well is assumed to have 1◦ average inclination, so the critical buckling load is (see Equation 12.3): Fcr = −23, 304lb (for 1◦ hole angle assumption), and the overpull force to eliminate buckling is Fop = Fcr − Fe = −23, 304 − (−132, 513) = 109, 209lb added tension. The total landing force would be 457,922 lb + 109,209 lb = 567,131 lb. This load should be checked to ensure a tension safety factor of 1.4. • To determine the approximate amount of stretch anticipated for 109,209 lb overpull with TOC at 10,000 ft, ∆L = F L/EAp = 109, 209 × 10, 000/ (30, 000, 000 × 13.57) = 2.68ft.
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Chapter 13
Casing Wear 13.1
Parameters for Casing Wear
Casing wear takes the form of a localized, crescent-shaped groove cut by a rotating drill string forced against a casing’s internal surface. Figure 13.1 shows where and how casing wear develops. The combination of high sidewall forces and extended drill string to casing contact around the kick-off section of a well profile puts this area at risk, but localized doglegs, e.g., from buckling, can cause severe wear wherever they occur. Casing wear ultimately leads to failure. However, before actual failure there are four effects: • The wear groove reduces the casing string’s pressure integrity which will affect well control, leak-off, testing and production procedures; • Casing and drill string tool joints both wear, the latter leading to expensive rebuild or replacement charges; • Rotational friction and hence surface torque can be high (a secondary effect not always observed); • The wear groove may act as a preferential start point for future corrosion. Casing wear is the result of a complicated system involving the relation between casing, tool joint and mud. Minimum casing wear can only be achieved by balancing the effect of each component. The best lubricant in the world will not perform with rough hard-banding. There are three different wear mechanisms which can occur, depending on the operating conditions. • Adhesive Wear. Also known as galling, adhesive wear involves the transfer of material from one surface to another by solid-phase welding, see Figure 13.2. Transfer commonly occurs from the casing to the tool joint. This process may result in the production of loose wear particles which can be flake like wear debris. • Abrasive Wear. Abrasive or machining wear involves the removal of material from one surface due to the cutting action of hard projections on another, see Figure 13.3. These hard projections will commonly be the tungsten carbide particles of tool joint hard-banding exposed as the softer binding EPT Drilling
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Tension
Cross Section AA Wear Groove
Kickoff A' Casing Wear RPM
Tooljoint Dogleg
A Section
Casing
Drill string
Tension BPAD003_089.ai
Figure 13.1. What Is Wear?
Tool Joint
Flake
Steel Casing Adhesion
Transport
Flake Formation BPAD003_090.ai
Figure 13.2. Adhesive Wear
material holding the particles in place wears away. Alternatively hard particles may become embedded in one surface and machine the other. The resulting wear debris resembles long chips or ”steel wool”. • Grinding wear occurs when hard particles become trapped between the tool joint and casing surfaces and abrade one or both. This can either cause ploughing and the formation of grooves or grinding producing a honed surface and fine powdery wear debris. See Figure 13.4. EPT Drilling
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Weld Matrix
Tool Joint
Tungsten Carbide
Chip
Steel Casing BPAD003_091.ai
Figure 13.3. Abrasive Wear
Hardmetal Tool
Steel Casing
Powder BPAD003_092.ai
Figure 13.4. Grinding Wear
There are two important points to note about the wear mechanisms: • The wear rate increases by two to three orders of magnitude through the transition from grinding to abrasive wear. Most casing wear is a type of machining and is generally caused by poor hard-banding specifications. • The wear process determines the condition of the two sliding surfaces which in turn governs the friction. It is interesting to note, however, that high friction and low wear can occur simultaneously, especially where the applied force is evenly distributed, e.g., a car brake shoe.
13.2
Predicting Casing Wear
Controlling the wear mechanism is the key to minimizing casing wear. However, it is impossible to rank individual parameters as each contributes to balancing the whole system. Practical tests have shown that tripping tools inside casing does not normally contribute more than five percent of the wear depth. This is EPT Drilling
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(1)
(2)
Rotation RPM
RPM
Tool Joint
Casing
Increased Area Decrease Pressure
Point Line Contact
BPAD003_093.ai
Figure 13.5. Constant Wear Force but Decreasing Wear Pressure
because (a) contact time is low, except at casing crossovers in high tension wireline operations, and (b) the wear mechanism is due to ploughing. Hence the vertical score marks in the wear groove typically seen on recovered casing. The CWear software tool is recommended for casing wear prediction. CWear is discussed more fully in Section 6.3.4.
13.2.1
Contact Pressure vs. Load
Figure 13.5 shows that as the wear groove deepens, the area of contact between tool joint and casing increases. For a constant side load or normal force, this equates to a decreasing contact pressure. It has been experimentally proven that the choice of wear mechanism is governed by the contact pressure between the two surfaces. Specifically the transition between machining and grinding appears to occur at approximately 250 psi (see Figure 13.6). In practice this means that the high initial contact pressure caused when tool joint and casing first touch, causes machine wear which, as the load is distributed, decreases quickly to a steady state of grinding wear. Figure 13.7 shows the empirical results of full-scale hard-banding/casing wear tests under two loads which validate this statement. Note how the wear rate flattens off when the wear groove depth reaches 0.15 in. Any wear or torque-drag software that outputs normal force can be used to calculate the side loading required to keep beneath the transition pressure of 250 psi at various groove depths. Figure 13.6 measures contact intensity as a pressure (force/area). On the other hand, most torquedrag software measures contact intensity as force per length of rotating tubular1 . The two may be related, provided the depth of the wear groove is known. Referencing the right-hand drawing in Figure 13.5, let fwear 1 Torque-drag
software typically utilizes the soft string model which does not include the detail of embedment of the rotating tubular in the stationary tubular displayed in Figure 13.5.
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Threshold Pressure: 250 psi
Wear Rate
Grinding Wear
0
100
200
Machining / Adhesive Wear
300
400
500
600
Contact Pressure (psi) BPAD003_094.ai
Figure 13.6. Transition Pressure - Grinding to Machining Wear
(see Equation 13.4 be the fraction of wall thickness remaining. Then to convert contact intensity measured as force per length of tubular to contact intensity as a pressure, multiply the former by the factor Contact Intensity [force/area] = Contact Intensity [force/length] / i h Dtj i h D )2 D 1 − fwear − 2ttj + (1−fwear 2t − 1 − 2t 2 (D − 2t) π − arccos hh i Dtj i Dtj D + 1 − fwear 2t 2t − 1 − 2t
(13.1)
which accounts geometrically for the arc length of contact between the two tubulars at a given value of fwear , or remaining wall thickness. As suggested in Figure 13.5, and for a constant contact force per length of rotating tubular, contact pressure will be enormous on first contact and decrease with accumulated wear (decreasing fwear ). An example is shown in Figure 13.8 for 13-3/8 in. 72 lb/ft casing worn by a 6-1/2 in. EPT Drilling
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24
Wear Factor
20 16 12 5000 lb/ft
8
7000 lb/ft 4 0 0.00
0.02
0.04
0.06
0.08
0.10
0.12
0.14
0.16
0.18
0.20
Wear Depth (in) BPAD003_095.ai
Figure 13.7. Experimentally Measured Wear Factor
tool joint. Assuming sufficient excess in the tubular design to admit 10% wear, a reasonable value of fwear to use in the above multiplier would be 0.9.
13.2.2
Well Design Guidelines
Before designing a well, consider “what-if” scenarios. What casing wear allowance will cover an unexpected change of plan at minimum initial design cost, e.g., a sidetrack? The higher the risk of drilling extra footage, the greater the wall thickness allowance or precautionary measures required. Extra rotating time can also occur because of stuck pipe, fishing and similar operations. If the drilling program is prone to such problems, then additional allowances should be made. Backreaming, if used, will result in higher side loads than the corresponding drilling operation2 . In some areas extensive backreaming is sometimes required, in which case the casing wear allowance should take this factor into account.
2 The
higher side load accompanying backreaming originates from the higher tension, and is magnified by the degree of hole curvature. See Equation 21.20 and the surrounding discussion.
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Figure 13.8. Example of Contact Intensity Multiplier Behavior, 13-3/8 in. 72 lb/ft casing, TJ OD 6.5 in.
13.2.3
Doglegs
Casing wear cannot occur unless the drill string touches the inside of the casing. As Figure 13.1 shows, this occurs when the drill string is pulled around or through a “dogleg”. The typical method for measuring doglegs is in degrees per l00 feet (or degrees per 30 meters). This gives an average value over the length. Unfortunately, casing wear often occurs around severe local doglegs (< 100 ft), and what appears to be a smooth survey profile may contain hidden curvature. In particular, drilling through buckled casing can cause severe wear. When designing a well profile, it is important to understand the effect a local dogleg would have on the life of the casing. Empirical data has shown that build and drop rates of directional wells can be locally exceeded by at least 1.75 times the planned rate. Well profiles should be checked for sensitivity to these unplanned doglegs by using the CWear software. There are no preferred well profiles to minimize casing wear, but high sidewall forces can be minimized by using a deep kickoff section. Because of this, most horizontal wells do not suffer severe casing wear as the side loading generated by the BHA in the horizontal section is generally low and more evenly distributed.
13.2.4
Estimation of Casing Wear
The following procedure (see Figure 13.9) provides a means of quickly determining whether casing wear may be a problem on a well. From this preliminary investigation it should be possible to decide whether a more detailed study is required. EPT Drilling
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Figure 13.9. Estimation of Casing Wear
13.2.4.1
Information Required
To perform a preliminary estimation of casing wear, the following information is required: • Type of tool joint hard banding; • Mud type (oil-based or water-based); • An estimate of drill string side load at the depth of interest, or alternatively the drill string tension (or compression) and the dogleg severity. Average values for a hole section are sufficient; • An estimate of the total rotating hours expected inside a casing string and the planned rotary speed; 13.2.4.2
Procedure
Three of the charts in this section are needed to estimate casing wear; be careful to select the correct charts. 1. Use Chart 1 to determine the casing wear factor. Use the Torque Drag module of WellPlan to estimate the drill pipe side load at the depth of interest. Alternately, estimate drill string tension (or EPT Drilling
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compression) and dogleg severity to calculate side load3 from Chart 1. Determine the wear coefficient of the tool joint hard-banding from Table 13.1. To estimate side load, read up from Drill Pipe Tension/Compression to the intercept with Dogleg then read across to Normal Force. Read across from Normal Force (ordinate) to the intercept with the appropriate Wear Coefficient in the table. Read down to the left hand x-axis for the Wear Factor. 2. According to tool joint diameter, select from Charts 2-4 to determine casing Wear Volume4 . Read up from Equivalent Rotating Hours (abscissa) to the intercept with the appropriate Wear Factor (from Chart 1). Read across to the ordinate for Wear Volume. As Charts 2-4 assume a rotary speed of 60 rpm, determine the number of equivalent rotating hours anticipated inside the casing string by equating one equivalent rotating hour to one hour of rotation at 60 rpm. Hence,
Total equivalent rotating hrs = Total rotating hrs ×
Rotary speed, rpm . 60
(13.2)
3. According to casing outside diameter and tool joint diameter select from Charts 5-12 to determine percent casing Wear Depth. Read up from the calculated Wear Volume (abscissa) to the intercept with the appropriate Casing Weight. Read across to the y-axis for percent Wear Depth5 .
% casing wear =
Reduction in thickness × 100% . Original thickness
(13.3)
This procedure should be repeated with small variations in input parameters (especially dogleg wear coefficient, and rotating hours) to obtain levels of confidence in the predicted wear. This will also indicate sensitivity to changes in well design and drilling parameters. This procedure is summarized in a decision tree in Figure 13.9. 13.2.4.3
Interpretation of Results
The predicted wear should be compared with the allowable wear to stay within the required design factors. The allowable wear can be obtained from StressCheck6 . A more detailed casing wear study should be considered if: • Sensitivity analysis gives wide variations in percent wear; 3 Ignoring
the contribution of the buoyed,rdistributed weight of the drill pipe along the low side of the hole, the normal 2 2 ~ force per length is (see Chapter 21) N sinα dβ + dα ., that is, the normal force per length is the product of the = Fe ds ds
effective tension and the dogleg severity. Shallow doglegs are more wear prone because of the associated tension. 4 Wear volume per unit length of casing is given by V = f N ~ w j πωDtj Ldr /Rp .
5 Wear (see previous step) is usually calculated as a lost volume. This step converts volume to a crescent shaped groove in the casing, and then determines from geometry the depth of the groove. 6 Unfortunately,
there is currently no automated means of comparing the predicted wear, either from the procedure in Section 13.2.4.2 or CWear, with the allowable wear as reported by StressCheck. The most straightforward means of making the comparison is to copy depth/predicted wear pairs and depth/allowable wear pairs to a spreadsheet such as Microsoft Excel and plot the two results. Depth intervals where predicted wear exceeds allowable wear should be investigated further.
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Table 13.1. Wear Coefficients of Tool Joint Hard-Banding Tool Joint
WBM
OBM
Smooth TC
10
5
Plain Steel
6
3
Wear Resistant Alloy Overlaysa
2
2
a
Armacor M, Arnco 200 XT, etc.
• A sidetrack is planned; • Extensive backreaming is planned; • Casing wear cannot be calculated with the charts; • Casing burst or collapse design is critical - often the case for HPHT if required drift is to be achieved. Full casing wear investigations can be performed by EPT. 13.2.4.4
Example
A 12-1/4 in. hole is being drilled to 3,500 m at an average rate of penetration (ROP) of 10 m/hr and a rotary speed of 120 rpm. A string of 54.5 lb/ft 13-3/8 in. casing is set at 1,500 m. At 500 m there is a 3 [◦ /100 ft] dogleg and the drill pipe tension is about 160,000 lbf . The hole is being drilled with oil-based mud and the drill string has 6-1/2 in. OD tool joints with tungsten carbide hard-banding. How much casing wear is expected? 1. From Chart 1: Wear Factor = 400; 2. From Chart 3: Wear Volume = 1.25 in3 /ft; 3. From Chart 5: Wear Depth = 20 percent of casing wall.
13.3
Casing Rating Calculations for Worn Casing
Casing wear reduces both the burst and collapse ratings.
13.3.1
Internal Yield Pressure
To allow for casing wear, the API burst rating is multiplied by fwear (see Chapter 9). fwear is given by % wear . (13.4) 100 If detailed thickness measurements are available then a revised API internal yield capacity for the worn casing can be calculated using actual measurements. Factors such as variation in yield strength, work fwear = 1 −
hardening, etc., are included in the burst uniaxial design factor. EPT Drilling
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Wear Factor Determination Wear Coefficient 6
5
4
3
2
1
Dogleg (deg/100ft)
Chart 1
10
7.5
5
4
200
3
150
Sideload (lbl/ft)
8
10
100
2
50
1
0 1,200
1,000
800
600
400
200
0
0 0
Wear Factor
50
100
150
200
250
300
Drillpipe Tension / Compression (1000 lbf) BPAD003_099.ai
Figure 13.10. Wear Estimation Procedure - Chart 1
13.3.2
Collapse
To allow for groove type wear, it may be assumed that the collapse strength is in direct proportion to the remaining wall thickness [48, 77]. This simply means that if, for example, 20% of the wall is worn away, then the collapse rating is 80% of that of the new casing7 . Both analyses and experiment indicate that the collapse rating calculated by direct proportioning, based on the remaining wall thickness, provides an accurate measure of collapse performance. This observation is true for casing subjected to external pressure only, and for crescent casing shaped wear over a small part of the circumference.
13.4
Considerations to Minimize Casing Wear
Highlighted below are various areas of the drilling operation which impact casing wear. These areas should be addressed during well planning and operating to minimize casing wear. 7 Do
not re-calculate a D/t based on a uniform reduction in wall thickness, then determine the appropriate collapse mode from API for the grade of the material, and then recalculate the collapse strength. This method will result in extremely low collapse ratings, and is only appropriate for wear around the entire circumference.
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Wear Volume Determination Wear Factor
Chart 2 (4.3/4" Tooljoints) 10
1200 1100 1000
Wear Volume (cu in/ft)
8
900 800 6
700 600
4
500 400 300
2
200 100
0 0
200
400
600
800
1,000
1,200
1,400
Equivalent Rotating Hours BPAD003_100.ai
Figure 13.11. Wear Estimation Procedure - Chart 2
Wear Volume Determination Wear Factor
Chart 3 (6.1/2" Tooljoints) 14
1200 1100
12
Wear Volume (cu in/ft)
1000 10
900 800
8
700 600
6 500 400
4
300 200
2
100 0 0
200
400
600
800
1,000
1,200
1,400
Equivalent Rotating Hours BPAD003_101.ai
Figure 13.12. Wear Estimation Procedure - Chart 3
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Wear Volume Determination Wear Factor
Chart 4 (8" Tooljoints) 16
1300 1100
14 1000 900
Wear Volume (cu.ln/ft)
12
800
10 700 600
8
500
6 400 300
4
200
2 0
100
0
200
400
600
800
1,000
1,200
1,400
Equivalent Rotating Hours BPAD003_102.ai
Figure 13.13. Wear Estimation Procedure - Chart 4
Wear Depth Determination Chart 5 (13.3/8" Casing / 6.1/2" Tooljoint) 60
54.5
61
Chart 6 (13.3/8" Casing / 8" Tooljoint) 60
68
54.5
61
68
50
50
40
40
Percent Wear
Percent Wear
Casing Weight (lb/ft)
30
30
20
20
10
10
0
Casing Weight (lb/ft)
0 0
2
4
6
8
10
0
Wear Volume (cu in/ft)
2
4
6
8
10
12
Wear Volume (cu in/ft) BPAD003_103.ai
Figure 13.14. Wear Estimation Procedure - Charts 5 and 6
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Wear Depth Determination Chart 7 (10.3/4" Casing / 4.3/4" Tooljoint)
Chart 8 (10.3/4" Casing / 6.1/2" Tooljoint)
60
60 51.0 55.5
45.5
Casing Weight (lb/ft)
50
50
40
40
Percent Wear
Percent Wear
45.5
30
Casing Weight (lb/ft)
30
20
20
10
10
0
51.0 55.5
0 0
2
4
6
8
0
10
2
Wear Volume (cu in/ft)
4
6
8
10
Wear Volume (cu in/ft) BPAD003_104.ai
Figure 13.15. Wear Estimation Procedure - Charts 7 and 8 Wear Depth Determination Chart 9 (10.3/4" Casing / 8" Tooljoint)
Chart 10 (9.5/8" Casing / 4.3/4" Tooljoint)
60 45.5
51
60
55.5
Casing Weight (lb/ft)
50
53.5
Casing Weight (lb/ft)
50
40
40
Percent Wear
Percent Wear
40 43.5 47
30
30
20
20
10
10
0 0
2
4
6
8
10
12
14
0
16
0
2
4
6
8
10
Wear Volume (cu in/ft)
Wear Volume (cu in/ft)
BPAD003_105.ai
Figure 13.16. Wear Estimation Procedure - Charts 9 and 10
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Wear Depth Determination Chart 11 (9.5/8" Casing / 5.12" Tooljoint) 60
40
43.5 47
Chart 12 (7" Casing / 4.3/4" Tooljoint) 60
53.5
Casing Weight (lb/ft)
50
26
29
32
Casing Weight (lb/ft)
50
40
Percent Wear
40
Percent Wear
23
30
30
20
20
10
10
0
0 0
2
4
6
8
10
12
14
16
0
Wear Volume (cu in/ft)
2
4
6
8
10
Wear Volume (cu in/ft) BPAD003_106.ai
Figure 13.17. Wear Estimation Procedure - Charts 11 and 12
13.4.1
Casing Material
• Steel. The relation between wear resistance and metallurgy for oilfield materials is complicated. It cannot be assumed that higher strength casings have greater wear resistance than lower strength casings. • Glass Reinforced Plastic (GRP). Experiments have shown that GRP casing wears six times more quickly than steel casing. GRP casing should not be used where there is potential for casing wear.
13.4.2
Crossovers (Including Centralizers and Cementing)
There are instances when linear wear is important, e.g., the wellhead wear bushing which has to act as a drillstring guide and withstand many thousand tool joint passes each hole section. Wellheads and combination string crossovers, if poorly designed, can present shoulders for the tool joints to hang up on. This would be of little consequence except that the hard-banding on the 18 degree taper of the tool joint cannot be ground smooth or flush. Figure 13.19 shows that this is the first point of contact between the tool joint and any exposed edges (including couplings) and can lead to excessive wear. All crossovers should have a shallow transition between diameters. Sharp corners must be avoided. Where crossovers join two different weights or sizes of casing, it is important to ensure that the transition is well supported. The stiffness of the two joined sections will be different, and if not well supported, they will tend to form a local dogleg. Effective support means positive centralization backed up with cement. EPT Drilling
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Figure 13.18. Effect of Groove Type Tool Joint Wear on Collapse Resistance, 9-5/8 in. 53.5 lbf/ft L-80 [77]
The placement of the top of cement (TOC) must be chosen to ensure that it does not lie in an area of high side wall forces as, again, the transition from “supported” to “free” pipe can form a local dogleg. Centralizers should never be placed over the casing couplings in sections prone to casing wear. The casing coupling tends to support the casing away from the wellbore if uncemented (Figure 13.20). If the standoff is enhanced by a centralizer, a hump or mini shoulder forms, for the 18◦ taper to wear against. Drill pipe protectors are ineffective under such circumstances. Several cases of this severe localized wear at couplings have been observed including instances in the tangent section of the well profile. Such wear causes an unquantifiable reduction in casing strength. To smooth out the profile, centralizers should always be placed over stop collars in the center of each length.
13.4.3
Tapered Casing Strings
It has been stated previously that the wall thickness, and hence mass, of casing should be increased where there is potential for casing wear. The output from CWear can be used to identify the appropriate sections that require this additional reinforcement. During the planning of the well, this will normally lead to thicker walled casing around the kickoff section. EPT Drilling
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Casing
Drillstring
Cross-over
RPM
Casing
BPAD003_108.ai
Figure 13.19. Tool Joint 18◦ Taper: First Point of Contact at Crossover
13.4.4
Hard-banding
“Wear-resistant alloy” hard-banded layers such as Armacor M and Arnco 200 XT are recommended by BP hard-banding guidance. Unlike the tungsten carbide overlays, the wear resistance does not depend on large dispersed hard particles; rather, wear resistance is achieved through the high uniform surface hardness. It is possible to produce a smooth “as welded” surface finish with these materials, such that it is often unnecessary to grind after welding. Previous experience within BP has been with flush hard-banded layers of these materials. Hence this is the “normally preferred” option. In this context “flush” means a coating with a diameter within ±1/32 in. that of the tool joint. However, recent evidence suggests that a “proud” hard-banding layer can be developed with these alloys (3/32 - 5/32 in. above the tool joint diameter–see GIS 02-102 Guidance Document for the Hard Facing of Drill String Components [60]) which does not result in increased casing wear but which can take advantage of the lower coefficient of friction offered by these alloys. In addition, effective wear coefficients are lower in proud hard metal layers. In flush hard-banding, the effective wear coefficients are due to the combined action of steel and hard material. In the past, hard-banding has consisted of a mild, steel weld matrix imbedded with particles of hard tungsten carbide to provide wear resistance. The matrix is applied by a gas arc welding process in three, one-inch bands. The tungsten pellets are fed separately into the weld “puddle”. To minimize the casing wear EPT Drilling
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Protector
Deflected Casing Tooljoint
Casing collar
BPAD003_109.ai
Figure 13.20. Casing Couplings and the Hump Effect
that this hard-banded layer can cause it is important to produce a smooth flush hard-banded layer. This is usually achieved by grinding the layer after welding. Tungsten carbide hard-banding is not recommended for any applications which involve rotation inside casing, but if absolutely necessary can be used to prevent wear of drilling assemblies in open hole. The use of components with this type of hard facing requires consideration and review. In addition to the OD hard-banding, there has historically been an additional weld band with three fingers on the 18◦ taper of the tool joint. This is designed to prevent undermining of the tool joint in open hole. In highly deviated wells (>45◦ ), this band can cause considerable damage to the casing couplings via the “hump” effect mentioned previously. When selecting new drill pipe, this 18◦ hard-banding can only be justified where exceptionally abrasive formations are likely to be encountered. Severe casing wear can still occur with tungsten carbide even if it is applied properly. Wear resistant alloys are preferred but if tungsten carbide must be used it should be to BP specification to minimize casing wear.
13.4.5
Drill Pipe Protectors
Drill pipe or casing wear protectors come in essentially two varieties–rotating and non-rotating. EPT Drilling
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Weld Matrix with Tungsten Carbide Particle Inserts
3 Weld Bands
Additional Weld Bond Plus Three Fingers
Tool Joint Box
BPAD003_110.ai
Figure 13.21. Tool Joint Cross Section
13.4.5.1
Rotating Drill Pipe Protectors
A rotating protector is an elastomer “stabilizer” designed to keep the drill pipe and casing surfaces separated. The protector should be treated as a cheap “throw-away” item devised to save drill string rebuilds and prevent casing wear. There are various elastomer profiles available, most of which are formed around a steel cage which is used to clamp the protector to the drill pipe body. The size and deformation of the elastomer is critical to ensure sufficient stand-off under downhole conditions. The outside diameter of the protector, measured at the surface, should be a minimum of in. greater than the tool joint, i.e., a 6-1/2 in. tool joint requires a minimum 7 in. drill pipe protector. Most protectors start life meeting this requirement but, during field use, they wear and must be checked and replaced on a regular basis. This means callipering and visually inspecting every protector for damage on each trip out of the hole. Rotating drill pipe protectors have unjustifiably received a poor reputation due to seemingly inexplicable failures. The majority of failures have occurred because of improper installation, poor rig site management and overloading. With regard to overloading, most protectors are positioned on the drill string in areas of high normal force. Normally an 18 in. steel tool joint is required to support this load instead. The Torque Drag module of WellPlan can be used to predict normal forces and check installation frequency to prevent overloading. When selecting rotating protectors choose the biggest, longest available to give maximum load distribution. Do not exceed manufacturer quoted side loadings–normal force is often quoted in pounds per foot and an average protector is only six inches long. Consider putting two protectors side by side to add support and to reduce the loading. Most pieces of equipment work more efficiently under less strain. Never rent or use second-hand protectors. EPT Drilling
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13.4.5.2
Non-Rotating Drill Pipe Protectors
Non-rotating protectors are the more modern version of the two types of protectors. In addition to preventing casing and riser wear, non-rotating protectors offer the benefit of potential torque reduction generated through the use of low friction fluid bearing designs. Typical designs include both clamp-on devices and subs. As with non-rotating devices it is important to know the operating limits of each tool. As a minimum the following information should be assessed during any evaluation: • Assembly / tool length; • Maximum outside diameter of tool; • Maximum operating side load (static and dynamic); • Maximum operating RPM; • Expected life of tool (typically number of revolutions for a given side load); • Maximum axial force before slippage–needed for clamp on devices As with any well planning process, it is important to be aware of other areas that could be impacted by the used of such devices. For example, the use of a large number of protectors could result in a significant ECD penalty.
13.4.6
Mud Types
Below is a description of the effect of each mud component on the wear process. Comments are valid for smooth flush tool joints operating under normal downhole conditions. The higher the ⋆ rating, the greater its effect on reducing casing wear. • Water based muds (⋆⋆)–very severe adhesive wear with friction. Caused by the lack of any solid barriers in the mud. • Oil based muds (⋆ ⋆ ⋆⋆)–reduced friction but potential for increased casing wear depending on hardbanding type and contact pressures (e.g., turning metal on a lathe with a lubricant). • Unweighted/weighted muds–in general introducing a weighting material such as bentonite, barite or drill solids into the system will reduce casing wear. However, the percentage volume of solids does not seem to affect the wear rate significantly. The solid particles reduce wear by acting as small ball bearings between the rolling surfaces, thus keeping them apart. The larger and smoother the solid particles, the greater the support and spacing between the two surfaces. Should the particle size be less than that of any projecting tungsten carbide particles in the hard-banding, then all the effect is lost. Barite (⋆ ⋆ ⋆⋆) being bigger than bentonite (⋆⋆) is therefore preferred. In addition, there is a limit to the hardness of the particles that can be used before abrasive wear starts to occur. This explains why barite performs better than either haematite (⋆⋆) or quartz (⋆). Too soft a material would simply be squashed out of the gap between tool joint and casing. Additional solids or particles added to a mud system already containing a weighting agent seem to contribute little extra to reduce casing wear (0-5%). Glass beads (1/2⋆) and similar products should be considered carefully. EPT Drilling
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• Sand/silt–has little or no effect on the wear rate. The particles of sand are too large to roll in the gap between tool joint and casing. In unweighted “simple” muds, adhesive wear is so severe that the abrasive contribution from the sand is negligible. In weighted muds, the sand is so diluted by the weighting agent that its effect is also negligible. • Lubricants (⋆⋆)–the effect of lubricants on friction and wear rate depends on the surface conditions of the casing and tool joint and the type and amount of solids in the mud. Lubricants create a film on the tool joint and casing surfaces with low gliding resistance. When the solids content of the mud increases, solid particles will penetrate the lubricant films. Friction will be partly determined by lubricant film/film contact, partly by particle/particle and partly by steel/particle contact. At a certain solids content, the particle layer apparently reaches a thickness that prevents all film/film contact thus eliminating the effect of any lubrication. Experimental tests of wear rates with various products has only shown worthwhile improvements in unweighted water based muds.
13.5
Measuring/ Monitoring Casing Wear
At the rig site there are three parameters that can be monitored and used as an indicator of casing wear–high torque (secondary indicator only), metal swarf in the mud returns, and worn tool joints. A combination of these is a definite sign of casing wear. None of the measurements are, however, quantitative and rig site personnel should use them only as warning tools. This is particularly true with metal swarf measurements as most ditch magnets are not capable of recovering a representative sample of the metallic content of the mud. To obtain an accurate assessment of the depth and location of the casing wear groove, a positive caliper measurement is required. There are three types of caliper:
13.5.1
Mechanical
A mechanical caliper typically uses multiple arms or fingers to follow and trace the contours of the internal casing surface. Measurements are either recorded on a downhole chart or are returned to surface using real time telemetry. These tools suffer from “average” radial resolution (typically 5-10% of the wall thickness), poor wall coverage, and only give inside diameter information.
13.5.2
Acoustic (Preferred)
Acoustic calipers measure the transit time and strength of an acoustic signal reflected from the casing wall inside and outside diameter boundaries to give both a radius and wall thickness measurement. Acoustic calipers are often limited by the solid particles in the mud reflecting the acoustic signals, and are best run in brine. An acoustic caliper is the first choice where thickness measurements are required for later assessment of performance properties.
13.5.3
Electromagnetic
Electromagnetic calipers use anomalies in a magnetic field induced in the casing wall to obtain only a qualitative assessment of imperfections. EPT Drilling
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Table 13.2. Caliper Tools Tool
Radial
Operating
Resolution
Conditions
Mechanical
⋆⋆⋆
⋆⋆⋆⋆⋆
⋆⋆⋆⋆⋆
⋆⋆
⋆⋆⋆⋆⋆
⋆⋆⋆⋆⋆
Acoustic
⋆⋆⋆⋆⋆
⋆⋆
⋆⋆⋆
⋆⋆
⋆⋆
⋆
⋆
⋆
⋆⋆
⋆
⋆⋆⋆
⋆⋆⋆
Electromagnetic
Reliability
Speed to
Cost to Run
Run
Worldwide Availability
Key: ⋆ ⋆ ⋆ ⋆ ⋆ = good → ⋆ = bad
13.5.4
Summary
The main logging contractors provide comparable equipment although there can be small differences in resolution and methods of recording the data. Most of the caliper tools were originally developed to measure corrosion; but since casing wear only involves metal removal, all tools should be set up to record maximum casing diameters only. As Figure 13.1 illustrates, the wear groove occurs in a localized section of the inner casing circumference - typically less than 30%. This leaves a significant untouched area in the as manufactured condition. A series of finger recordings over the latter section is sufficient to determine the nominal casing diameter, thus negating the need for a baseline caliper. Table 13.2 shows how to select the appropriate caliper tool to measure casing wear.
13.6
Design Imperatives for Casing Wear
The following recommendations, if followed, help minimize casing wear. Listed in order of importance, 1. Tool joint hard-banding must be to the BP specification. 2. Design well trajectories with changes of less than 2◦ /100 ft. 3. Wear rate depends on contact pressure, not normal force. The first 0.15 inches of wall thickness will be lost quickly. 4. Design the risk of having to sidetrack into the casing design. 5. Drill pipe protectors will reduce casing wear but only if managed properly. 6. Ensure that the casing around potential doglegs is well supported, i.e.cemented and centralized. Localized wear at the couplings will occur. Do not put centralizers over couplings. 7. Beware tripping wear at crossovers. 8. Increase the wall thickness but not necessarily the casing grade. EPT Drilling
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9. Use a mechanical multi-finger caliper to measure wear in mud weights greater than 10.8 ppg (1.3 SG). Use rotating acoustic tools in brine or low weight muds. 10. Inspect tool joints, monitor drilling torque and measure ditch magnet returns at the rig site as warning tools for casing wear.
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Chapter 14
Temperature Considerations 14.1
Temperature Issues
Landmark’s Drill and Prod Wellcat modules are recommended for determining temperature profiles for high temperature casing designs. Most casing designs can use the default temperature profiles built into StressCheck. For high temperatures and pressures, and for all tubing designs, the more advanced analysis available in Wellcat may be used to obtain an economic design. If thermal modeling software is not available, the procedures described in this section provide sufficient accuracy for most tubular designs. However, when the bottom hole static temperature (BHST) exceeds 250◦ F or water depth exceeds 3,000 ft. (1,000 m), use of a temperature model is required. Consideration must be given to the yield derating of tubulars, described later in Paragraph 14.7. Temperature profiles must be determined for each load case. Temperature profiles required for each design are listed in Table 14.1. The abbreviations are use as subscript identifiers of temperature in all discussion to follow. The subscript “Cmt” refers to that instant when the casing or tubing is considered to be initially fixed, e.g., when the cement or packer fixes the axial position of the string. For converting from Fahrenheit (◦ F) to Centigrade (◦ C)
Table 14.1. Temperature Profile Subscript Abbreviations
EPT Drilling
Abbreviation
Temperature
S
Static (undisturbed) temperature
Cmt
Cemented/landed temperature
C
Drilling circulation temperature
P
Producing temperature
Surf
Static surface temperature 211
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◦
C = (◦ F − 32)/1.8.
(14.1)
For converting from Centigrade (◦ C) to Fahrenheit (◦ F) ◦
F = 1.8(◦ C) + 32.
(14.2)
Changes in temperature result in length changes for unrestrained pipe. Casing and tubing is usually held at the wellhead and by cement (casing) or a packer (tubing) so that the movement is restrained1 . This results in forces being generated which must be considered in design. It is the change in temperature that impacts tubular designs, ∆T = Average Service Temperature–Average Initial Temperature. The following sections describe how to determine the temperature profiles needed to determine the temperature change ∆T .
14.2
Static Temperature Profile
The static temperature profile (TS ) is defined as the surface temperature plus the natural geothermal gradient and, for onshore wells, can be calculated at the depth of interest assuming a linear temperature versus depth relation, TS [◦ F] = TSurf [◦ F] + γT [◦ F/100 ft] z [ft TVD] /100,
(14.3a)
TS [◦ C] = TSurf [◦ C] + γT [◦ C/30 m] z [m TVD] /30,
(14.3b)
TS [◦ C] = TSurf [◦ C] + γT [◦ C/30 m] z [m TVD] /30.
(14.3c)
or in Hybrid units,
or in SI units,
For offshore wells, if the water depth is greater than 500 ft. (150 m), the temperature at the mudline should be considered when determining the static temperature profile. Temperature at the mudline varies with geographic location. The information in Table 14.2 can be used as a guideline. In order to calculate the static temperature profile for offshore wells, use the mudline temperature (Tml ) and the water depth (zw ) as shown in Equation 14.4. TS [◦ F] = Tml [◦ F] + γT [◦ F/100 ft] (z − zw ) [ft TVD] /100,
(14.4a)
TS [◦ C] = Tml [◦ C] + γT [◦ C/30 m] (z − zw ) [m TVD] /30,
(14.4b)
or in Hybrid units,
1 In
the case of tubing, and less frequently in casing, the installation may not restrain the tubular at its lower end. In such installations, tubular movement, rather than axial force is generated. The initial temperature is still defined as that time when the tubular reaches its equilibrium position, and prior to service
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Table 14.2. Variation of Mudline Temperature with Water Depth Water Depth
Gulf of Mexico
North Sea
TSurf
80◦ F (27◦ C)
60◦ F (16◦ C)
500 ft. (150 m)
50◦ F (10◦ C)
45◦ F (7◦ C)
1500 ft. (450 m)
45◦ F (7◦ C)
40◦ F (4◦ C)
3000 ft. (900 m)
40◦ F (4◦ C)
40◦ F (4◦ C)
γT
1.0 to 1.2◦ F/100 ft (0.55 to 0.66◦C/30 m)
1.2 to 1.5◦ F/100 ft (0.66 to 0.82◦C/30 m)
or in SI units,
TS [◦ C] = Tml [◦ C] + γT [◦ C/30 m] (z − zw ) [m TVD] /30,
(14.4c)
at the depth (TVD) of interest, z. Equation 14.4 assumes a single temperature gradient below the mudline. Often the temperature gradient below the mudline is piecewise linear, with a shallow temperature gradient that may be as high as 7-10◦F/100 ft in the first 3-500 ft. below the mudline. In such an instance, Equation 14.4 should be replaced by the slightly more complicated expression
TS [◦ F] =
or in Hybrid units,
or in SI units,
T [◦ F] + γT [◦ F/100 ft] (z − zw ) [ft TVD] /100 ml
if z < zsh (14.5a)
Tml [◦ F] + γT sh [◦ F/100 ft] (zsh − zw ) [ft TVD] /100
+γT [ F/100 ft] (z − zsh ) [ft TVD] /100 ◦
if z < zsh ,
T [◦ C] + γT [◦ C/30 m] (z − zw ) [m TVD] /30 if z < zsh ml ◦ ◦ ◦ TS [ F] = Tml [ C] + γT sh [ C/30 m] (zsh − zw ) [m TVD] /30 +γT [◦ C/30 m] (z − zsh ) [m TVD] /30 if z < zsh , T [◦ C] + γT [◦ C/30 m] (z − zw ) [m TVD] /30 if z < zsh ml TS [◦ F] = Tml [◦ C] + γT sh [◦ C/30 m] (zsh − zw ) [m TVD] /30 +γ [◦ C/30 m] (z − z ) [m TVD] /30 if z < zsh . T sh
(14.5b)
(14.5c)
The static temperature profile consists of a minimum of two temperatures (surface temperature and BHST). Bottom hole static temperature is determined by using Equation 14.3 or 14.4 and substituting the well depth for the depth of interest. EPT Drilling
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Figure 14.1. Example Static Temperature Profile
14.2.1
Example Calculation of Static (Undisturbed) Temperature Profile
A North Sea well in 1,500 ft. (457.2 m)of water, with a true vertical depth of 13,500 ft. (4,114.8 m)has a (sub-mudline) temperature gradient of 1.4◦ F/100ft (0.766◦C/30m). The surface temperature is 50◦ F and the mudline temperature is 40◦ F (4.44◦ C). Compute the static temperature profile for the wellbore. Using Equation 14.4 the temperature at TD is TS [◦ F] = 40 [◦ F] + 1.4 [◦ F/100 ft] (13, 500 − 1, 500) [ft TVD] /100 = 208 [◦ F] ,
(14.6a)
or in Hybrid units, TS [◦ C] = 4.44 [◦ C] + 0.766 [◦ C/30 m] (4, 114.8 − 457.2) [m TVD] /30 = 97.8 [◦ C] ,
(14.6b)
or in SI units, TS [◦ C] = 4.44 [◦ C] + 0.766 [◦ C/30 m] (4, 114.8 − 457.2) [m TVD] /30 = 97.8 [◦ C] .
(14.6c)
This value, along with the surface and mudline temperatures allows the creation of the following temperature profile.
14.3
Cementing Temperature Profile
If the bottom hole static temperature (BHST) is less than 165◦F (75◦ C), the static temperature profile shall be used as the cementing temperature profile. If the BHST is greater than 165◦ F (75◦ C), the cementing EPT Drilling
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temperature profile (TInit ) must be calculated. The cementing temperature establishes the base case that is locked in as the cement sets. All other service load temperatures are compared with the cementing temperature profile in order to determine ∆T . The heat transfer history of the well affects the cementing temperature profile. For example, circulation usually cools the lower part of the well and heats the upper part. While these effects can be analyzed using the Dril module of Wellcat, a reasonable manual approximation is given by
TBHC [◦ F] = (1.342 − 0.2228γT [◦ F/100 ft] )TBHS [◦ F] + 33.54γT [◦ F/100 ft] − 102.1,
(14.7a)
or in Hybrid units,
TBHC [◦ C] = (1.342 − 0.4075γT [◦ C/30 m] )TBHS [◦ C] + 26.83γT [◦ C/30 m] − 50.64,
(14.7b)
or in SI units,
TBHC [◦ C] = (1.342 − 0.4075γT [◦ C/30 m] )TBHS [◦ C] + 26.83γT [◦ C/30 m] − 50.64,
(14.7c)
TBHCmt = TBHC + (TBHS − TBHC )/4,
(14.8)
TSurf Cmt = TSurf + 0.3(TBHCmt − TSurf ).
(14.9)
Equation 14.7 was developed by Kutason and Taighi [49] and is based on field measurements taken from 79 deep wells. Comparisons with Wellcat have shown that Equations 14.7–14.9 provide temperature profiles within ±10◦F. This is adequate for casing design work. Comparisons fell to ±20◦F for water depths in excess of 3000 ft. Under these conditions, a Wellcat temperature analysis should be used to determine the temperature profiles. The TCmt profile can be developed after calculating the TSurf Cmt and TBHCmt .
14.3.1
Example Calculation of Cementing Temperature Profile
A North Sea well in 450 ft. of water, with a true vertical depth of 13500 ft. has a (sub-mudline) temperature gradient of 1.3◦ F/100ft. The surface temperature is 60◦ F and the mudline temperature is not considered in this calculation, as the water depth is less than 500 ft. Compute the cementing temperature profile for the wellbore. Using Equation 14.3a the temperature at TD is TT D = 60 + 1.3(13500)/100 = 235.5 [◦ F] .
(14.10)
This value, along with the surface temperature (mudline temperature is ignored) allows the creation of the static temperature profile. Using Equations 14.7a–14.9, EPT Drilling
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Figure 14.2. Example Cementing Temperature Profile
TBHC = (1.342 − 0.2228 1.3)235 + 33.54(1.3) − 102.1 = 189 [◦ F] ,
(14.11)
TBHCmt = 189 + (235 − 189)/4 = 200 [◦ F] ,
(14.12)
TSurf Cmt = 60 + 0.3(200 − 60) = 102 [◦ F] .
(14.13)
These values allow the creation of the cementing temperature profile in Figure 14.2.
14.4
Drilling Temperatures
The temperature increases created by drilling ahead can result in casing elongation above the cement top or in uncemented sections. The elongation can lead to helical buckling if axial compression is created. Chapter 12 addresses buckling issues. For casing designs above the top of cement (TOC), the average temperature increase created by drilling circulating temperatures (TC ) are compared with the average temperature of the cementing temperature profile. Average temperature changes are used in order to compensate for the entire length change. The following equations may be used to determine the drilling temperature profiles: TC3 [ F] ◦
EPT Drilling
at surface = TC2
2 γT [◦ F/100 ft] [ F] − zDSOH [ft TVD] (0.8) , 3 100 ◦
216
(14.14a) BP Confidential
or in Hybrid units, TC3 [◦ C]
2 γT [◦ C/30 m] zDSOH [m TVD] (0.8) , 3 30
(14.14b)
2 γT [◦ C/30 m] [ C] − zDSOH [m TVD] (0.8) , 3 30
(14.14c)
at surface = TC2 [◦ C] −
or in SI units, TC3 [ C] ◦
at surface = TC2
◦
TC2
at 2/3 DSOH = 0.9TBHS ,
(14.15)
at DSOH = 0.95TBHS .
(14.16)
TC1
Drilling circulating temperatures between the surface and 2/3 DSOH can be interpolated to define the profile.
14.5
Production Temperatures
Production temperatures are the most critical for casing and tubing designs. The following steps can be used for the majority of producing wells. However, high rate (>5000 BPD or >10 MMCFD) wells or high temperature (>250◦F) wells require additional temperature modeling with Wellcat. The production temperature profile for casing is based on the producing zone bottom hole static temperature and can be determined as follows: 2 [ F] − zf [m TVD] 3
γT [◦ F/100 ft] 0.7 , 100
(14.17a)
2 TSurf P [◦ C] = 0.95TBHS [◦ C] − zf [ft TVD] 3
γT [◦ C/30 m] 0.7 , 30
(14.17b)
2 [ C] − zf [ft TVD] 3
γT [◦ C/30 m] 0.7 , 30
(14.17c)
TSurf P [ F] = 0.95TBHS ◦
◦
or in Hybrid units,
or in Hybrid units, TSurf P [ C] = 0.95TBHS ◦
TP
TP
◦
at 2/3 TD = 0.95TBHS ,
(14.18)
at producing zone = TBHS .
(14.19)
TP for other depths can be interpolated between the appropriate depths. For tubing designs, TP is calculated using the same equations. However, TSurf P is modified as follows, 2 γT [◦ F/100 ft] TSurf P [◦ F] = 0.95TBHS [◦ F] − zf [ft TVD] (0.5 , 3 100
(14.20a)
or in Hybrid units, EPT Drilling
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2 γT [◦ C/30 m] . TSurf P [◦ C] = 0.95TBHS [◦ C] − zf [m TVD] (0.5 3 30
(14.20b)
2 γT [◦ C/30 m] TSurf P [◦ C] = 0.95TBHS [◦ C] − zf [m TVD] (0.5 . 3 30
(14.20c)
or in Hybrid units,
14.5.1
Example Calculation of Drilling and Producing Temperature Profiles
A North Sea well in 500 ft. of water, with a true vertical depth of 13500 ft. has a (sub-mudline) temperature gradient of 1.3◦ F/100ft. The surface temperature is 60◦ F and the mudline temperature is 40◦ F. The bottom hole static temperature is 235◦ F. Compute the drilling temperature profile for the wellbore. The static (undisturbed) temperature profile is defined in the problem statement. Using Equations 14.14a– 14.16, the drilling temperature profile is calculated as TC3
2 1.3 at surface = 212 − 13, 500 (0.8) = 118 [◦ F] , 3 100
TC2
(14.21)
at 2/3 DSOH = 0.9 (235) = 212 [◦ F] ,
(14.22)
at DSOH = 0.95 (235) = 223 [◦ F] .
(14.23)
TC1
Using Equations 14.17a–14.19, the producing temperature profile is calculated as TSurf P = 0.95TBHS −
TP
TP
1.3 2 (13, 500) (0.7 = 141 [◦ F] , 3 100
(14.24)
at 2/3 TD = 0.95 (235) = 223 [◦ F] ,
(14.25)
at producing zone = 235 [◦ F] .
(14.26)
StressCheck uses a default of bottom hole temperature from reservoir to wellhead. This may be unduly conservative for low flow rates. Again Wellcat is available to refine predictions.
14.6
Miscellaneous Temperature Profiles
14.6.1
Bullheading
During drill stem testing (DST) or production, mud or completion fluids are used to bullhead down the tubing to kill the well. To estimate the bullhead kill temperature, the following should be used. EPT Drilling
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Figure 14.3. Example Drilling and Production Temperature Profiles
Table 14.3. Bullheading Temperature Recommendations
14.6.2
Depth
Temperature
0
Surface temperature of fluid
2/3 production zone
2/3 TBHS @ depth
Production zone
2/3 TBHS @ depth
Long Term Water or Gas Injection
For long term water injection at rates above 20,000 bbl/day, or gas rates above 40 mmscf the following can be used to establish the temperature profile. For short duration or low flow rates a Wellcat temperature prediction should be used. For example with a short cycle time (i.e., days) alternate water gas injection scheme, using surface injection temperature could
Table 14.4. Long Term Injection Temperature Recommendations
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Temperature
0
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Figure 14.4. HPHT Well Schematic
be unnecessarily conservative. Wellcat can be used to determine temperature distributions. Figures 14.4 and 14.5 provide an example of high temperature well testing for North Sea Operations. Note the relatively high temperatures near the mudline/wellhead as compared to static temperature. EPT Drilling
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Figure 14.5. HPHT DST Temperature Profiles
14.7
Yield Stress Derating
Table 14.5 (or see Figure 14.6), imbedded in StressCheck via the BP template, lists the yield strength deratings for temperature. Although the entries are the global BP default recommendation, there can be wide variations between seemingly similar materials from different manufacturers. When design yield strength has a critical influence on weight or grade selection, and conservative assumptions are economically undesirable, it is necessary to ensure by testing that the yield strength achieved in practice at elevated temperatures at least matches that assumed in design, and that the proposed manufacturer can achieve the requisite properties. Such testing can be expected to require about a month, and requires the involvement of an EPT material specialist. In tubular design it is assumed that the classical material properties of Young’s modulus and Poisson’s EPT Drilling
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Table 14.5. Recommended Yield Strength Temperature Derating Grade
Temp
Deration
Temp
Deration
Temp
Deration
Temp
Deration
Temp
Deration
(◦ F)
Factor
(◦ F)
Factor
(◦ F)
Factor
(◦ F)
Factor
(◦ F)
Factor
StressCheck Default
68
1
125
0.99
210
0.97
300
0.95
400
0.92
API 5CT, 5L
68
1
125
0.99
210
0.97
300
0.95
400
0.92
C110
68
1
125
0.975
210
0.945
300
0.90
400
0.86 0.90
C125
68
1
125
0.97
210
0.94
300
0.92
400
Duplex 80
68
1
125
0.96
210
0.90
300
0.87
400
0.86
Duplex 125
68
1
125
0.96
210
0.90
300
0.84
400
0.82
API 5CT 13CR
68
1
125
0.98
210
0.95
300
0.92
400
0.90
S13CR95
68
1
125
0.975
210
0.955
300
0.925
400
0.90
S13CR110
68
1
125
0.98
210
0.93
300
0.885
400
0.88
Austenitic
68
1
125
0.93
210
0.87
300
0.80
400
0.73
Ni-3Mo
68
1
125
0.97
210
0.95
300
0.87
400
0.78
Ni-6Mo
68
1
125
0.97
210
0.95
300
0.87
400
0.78
G3
68
1
125
0.96
210
0.90
300
0.85
400
0.79
C-276
68
1
125
0.96
210
0.90
300
0.85
400
0.79
SS
1
Correction Factor
0.95
0.9
API 5CT, 5L C110 C125 Duplex 80 Duplex 125 API 5CT 13Cr S13CR95 S13CR110 Austenitic SS Ni-3Mo, Ni-6Mo G3, C-276
0.85
0.8
0.75
0.7 50
100
150
200
250
300
350
Temperature, F Figure 14.6. Yield Strength Temperature Derating Factors
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ratio, are not functions of temperature.
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Chapter 15
Special Design Cases 15.1
Jackup Structural Conductor Design Guidelines
The conductor (or drive pipe) is fundamental to the integrity of the well and the containment of well fluids when drilling from a jackup rig. For this reason, it is important to check the conductor design even though in the majority of cases a standard design may be satisfactory and neither basic calculations nor detailed analysis are necessary. The following sections outline the key factors in jackup structural conductor design and offer a design selection procedure.
15.1.1
Loads
The conductor is subjected to a number of internal and external loads which combine to cause bending, compression, buckling and fatigue: • Wave loading; • Current loading; • Internal casing weight/pretension; • Self weight; • Drilling fluid density; • Wellhead/BOP weight. Wave and current loading deflect the conductor and apply bending forces which are normally greatest in the wave zone. Internal casings, conductor, wellhead/BOP and drilling fluid densities are added to give a compressive load which reaches a maximum at some point below the mudline. The combined compressive and bending forces tend to cause buckling (although the load from internal casing strings does not normally contribute to buckling [89]). Fatigue damage is caused by the fluctuating effect of wave loading and, in certain current regimes, by vortex induced vibration (VIV). EPT Drilling
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15.1.2
Environmental Conditions
Extreme design wave and current conditions are normally based on a ten year return period. UK HSEQ guidelines require that fixed structures be designed for fifty year return conditions. However, jackup conductors are not permanent installations so a shorter return period is generally acceptable. In the Gulf of Mexico, conductors are typically designed for the 99.9% exceedance or the ten year return storm for the particular drilling period. In tropical climates which are subject to hurricanes or typhoons, there is a large difference between the ten year hurricane and the ten year non-tropical storm. The time of year during which the well is drilled is thus also important. Scatter diagrams or wave exceedance data are required to determine fatigue due to cyclic wave loading. Again the time of year is important. In the Gulf of Mexico, for example, fatigue damage can typically be fifty times worse during the winter than during the summer. Current exceedance data is required to determine fatigue damage due to vortex induced vibration. In a region where currents are dominated by tidal influences, such as in the North Sea, good current statistics can be obtained. In many other areas where currents are dominated by general circulation patterns, statistical data are unavailable and reasonable analysis is not feasible. Although pure axial and bending stresses must be within allowable limits, the limiting factor in jackup conductor design is typically buckling. In deeper water the limit is a combination of dynamic bending and buckling. API RP2A [7] and the AISC Steel Construction Manual [6] give buckling criteria based on an interaction ratio which combines axial and bending forces: Fa Fb + < 1. (Fa )allowable (Fb )allowable
(15.1)
where the denominators include a safety factor. The allowable axial and bending forces depend on the end conditions and the slenderness ratio of the conductor. The safety factor inherent to all AISC designs is generally 1.66. However, in most cases the criteria given by API and AISC may be outside their range of applicability. The best approach is generally to split the relation into three parts: 1. The internal axial load which does not cause buckling as long as the casings are well centralized at the top; 2. The top load and self weight which does cause buckling and should be assessed in a global sense; 3. Finally, a bending term due to environmental loads which interact with buckling. API and other codes generally allow a reduction of 1.33 of the safety factor on the last term only. Since these calculations must include dynamic wave and inertia effects, as well as careful interpretation of the results, it is not practical to perform a design storm check without computer analysis and expert advice.
15.1.3
Fatigue Due to Cyclic Wave Loading
Given the expected wave climate over the duration of the well, a fatigue analysis considering the dynamic response of the conductor to cyclic wave loading must be performed. A simple deterministic analysis will EPT Drilling
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typically be sufficient. In many areas the design of the conductor will not be substantially influenced by fatigue. However, in the Gulf of Mexico, for example, fatigue is critical for operations during the winter. At that time, the maximum wave is low (no hurricane), and the currents are generally low. Under these conditions, the design will be entirely governed by wave cyclic fatigue or wave induced vortex vibrations.
15.1.4
Vortex Induced Vibration Fatigue
The major cause of fatigue damage and failure in jackup conductors is vortex induced vibration. This occurs when one or more natural frequencies are excited by current velocities or by large waves in the “lock-on” range. The lock-on range is defined in terms of the dimensionless reduced velocity,
vr = 12 ×
vw [ft/s] , ωn [1/s] D [in]
(15.2a)
or in Hybrid units,
vr = 39.37 ×
vw [m/s] , ωn [1/s] D [in]
(15.2b)
vw [m/s] . ωn [1/s] D [mm]
(15.2c)
or in SI units,
vr = 1, 000 ×
The most damaging, current-induced, cross-flow vibrations occur in the reduced velocity range from 4.5 to 9.0. If the conductor design is susceptible to current induced vortex induced vibration, and current statistics are available, detailed computer analysis should be carried out to determine the minimum fatigue life. If there are no reliable current statistics, or if vortex induced vibrations are expected to be caused by waves, then the assessment of the fatigue damage is more complex.
15.1.5
Detailed Design Analysis
If detailed analysis is necessary, it should be carried out by one familiar with the techniques using a suitable dynamic structural analysis program (assistance can be obtained from EPT). The exact procedure will vary according to specific design requirements, but will generally include the following: 1. Determination of environmental conditions; 2. Static analysis; 3. Dynamic analysis; 4. Fatigue analysis. Determination of the environmental criteria will establish maximum wave and current, wave climate and current regime. In addition, a key parameter in the analysis is the drag coefficient. This will vary according EPT Drilling
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to the current velocity, pipe diameter and roughness due to marine growth or vortex suppression device. Site specific geotechnical information is also required. The static analysis performs a basic stability check and can be used to determine the effect of rig offset. The dynamic analysis with extreme wave and current conditions is used to determine maximum stresses and perform the design check. The fatigue analysis should consider both cyclic wave loading and vortex induced vibration to determine the minimum fatigue life at critical locations. Based on the above analyses, a particular design can be established. For many shallow water locations, a standard design is acceptable and detailed analysis is unnecessary. The recommended standard design is a 30 in. diameter × 1.0 in. wall grade X52 conductor with one of the conductor connectors listed in Table 20.36, with design penetration 50 to 80 m (165 to 265 ft) below mudline. The limiting envelopes for this design are shown in Figure 15.1, and are defined in terms of water depth and current velocity by assuming the following typical values for sea state, air gap, BOP stack, and soil conditions: • Seastate: Hmax = 50 ft, Tmax = 12.5 secs • Air gap: MSL to BOP = 90 ft • BOP stack: Weight = 100,000 lbf transferred directly onto the conductor • Soils: Point of fixity = 10 ft below mudline • Casing Loads: Mudline suspension has been assumed with no cement above mudline. The envelope in Figure 15.1 is based on analysis detailed in BPE file note PT/1/65-65 dated 28Aug91. The envelope does not consider cyclic wave fatigue or wave induced vortex vibrations, but does include current VIV effects. Wells with a duration in excess of four months may require additional verification. The curved section of the limit (from 2.8 to 10 ft/sec) is the VIV lock-on line. The cutoff at 280 ft corresponds to 67% of yield. The “Possible Region” will require investigation into actual maximum wave, wave climate, fatigue and wave VIV to confirm adequacy. This curve is not adequate for free standing conductors. Jackup conductors which are within the acceptable envelope will not normally require further analysis. Cases which fall outside the acceptable envelope or when unusual procedures or conditions arise should be referred to an appropriate specialist for detailed analysis. However, in that region, the standard 30 in. × 1 in. design can generally be made to work. Cases in the unacceptable region will definitely need action and will generally not be possible for a 30 in. × 1 in. design. If the standard 30 in. × 1 in. conductor is unacceptable, detailed analysis will be necessary and the following design options should be considered: 1. Thick-walled pipe; 2. Large diameter pipe; 3. Vortex suppression device; 4. Tensioning system. EPT Drilling
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Figure 15.1. Jackup Design Envelope
The use of thick-walled (1.25 in., 1.5 in.) or larger diameter (36 in., 42 in.) pipe should be the first consideration regardless of whether the limiting factor is buckling or fatigue life. An alternative option for vortex induced fatigue is to run a suppression device. The preferred design is the helical strake which can be either a bonded rubber or manilla rope construction. Most suppression devices increase the drag coefficient of the conductor which tends to increase the effect of dynamic wave and static current loading. Some deep water jackup rigs have a conductor tensioning system. This can be used to prevent buckling although top tension may increase dynamic and fatigue stresses. A tensioning system also reduces the deck load available on the jackup.
15.1.6
Design Selection Procedure
The basic procedure is illustrated in Figure 15.2 which outlines the typical design/analysis stages and highlights the key decisions. All the above assumes that the conductor is to last no longer than the drilling and testing of the well EPT Drilling
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Figure 15.2. Jackup Design Selection Procedure
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and that it is laterally supported by the jackup above the waterline. In shallow water (less than 75 ft), a discovery well is sometimes left as a free standing conductor until development. If this is a possibility, the conductor must be designed more rigorously. The procedures outlined herein remain valid but the envelopes of Figure 15.1 definitely do not apply. The engineering skills needed to design marine conductors are more in the areas of ocean and structural engineering than drilling engineering. Therefore, it is always recommended that such expertise be consulted before selecting a conductor. Worldwide assistance can be obtained from EPT. In addition to [7] and [6], further detailed information on jackup conductor design, buckling criteria, fluid loading and dynamic analysis can be found in [38], [2], [1] and [14].
15.2
Annulus Pressure Build-up Due to Temperature
In well design, annular pressure build-up (APB) refers to the pressure change in a fluid in a closed annulus [37]. The phenomenon is particularly relevant to offshore wells where annuli may be trapped by terminating a casing string(s) at the mudline [18, 34, 41, 79]. The APB phenomenon, however, can occur in any annulus that is not vented [73].
15.2.1
APB Calculation and Mitigation Guidelines
Common practice is to conduct a first-pass “screening”’ calculation to determine whether a well design is potentially threatened by APB-induced failure modes. When calculating APB for such screening purposes, the following principles shall apply: • Except in extremely favorable circumstances, solids will settle. A convenient mitigator for APB is the strength of the formation (as compared to the casing) at the shoe of the casing forming the outer annulus boundary. As pressure builds, one might expect formation fracture to alleviate APB. Unfortunately, experience indicates that time will often render an initially open annulus closed, thus isolating the annulus from the weaker formation. This isolation may be caused by solids settling from the drilling fluid placed in the annulus, or it may be caused by wellbore instability in the vicinity of the outer casing shoe. The phenomenon occurs frequently enough in some geographic locations that a prudent design principle is to treat all annuli “open” to a formation as closed. • The hottest production temperature profile will be used. The hottest temperature profile for any well may not be that associated with early production. For example, water has high heat capacity, and the highest temperature that a well may experience can be associated with late-life production, which corresponds to the onset of water production. • Each annulus must stand on its own. If all annuli are heating simultaneously, the ensuing incremental pressures may be high, but the pressure differential between two strings acting to collapse or burst the intervening casing may still be within acceptable limits. This argument, however, ignores the possibility of a connection leak, or of a failure of the two strings at either end of the radial chain of EPT Drilling
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casings whose inner or outer annuli are not subjected to a thermally induced pressure increase1 . For these reasons, when designing for APB, each annulus should be addressed with only APB on that annulus, and without supporting APB from neighboring annuli. • A multiplier of 1.1 will be applied to all standard casing design factors. Thermal predictions rely upon a wide range of production and modeling parameters—flow rate, bottom-hole temperature, hydrocarbon composition, choice of multi-phase flow model, etc.—so a standard 10% increase is added to all design factors associated with APB-induced loads. For example, in the case of collapse loading, the target design factor becomes 1.1, once the string in question has been appropriately derated for drilling wear. When calculating APB with a software package such as Wellcat it is common to run (at least) initial APB estimates with all annuli closed. This will produce conservatively high APB pressures, as closing all annuli results in high pressures on all annuli, and, therefore, stiff annuli2 . All calculated APBs will be higher than might be possible in an individual load case. However, the myriad combinations of APB and no APB on annuli can render a more accurate (and less conservative) procedure untenable. A specialist within EPT should be consulted before designing casing strings based solely on screening calculations. Given the conservatively calculated APB values described in the previous paragraph, an individual casing string is then investigated, either from the viewpoint of internal or external pressure differential, by applying APB on the load side of the tubular and no APB on the other side of the tubular (i.e., each annulus must stand on its own). This incremental thermal pressure is to be applied at the top of the annulus in addition to any other pressure present. The internal and external fluids bounding the tubular can either both be original fluid densities, or can both be degraded by solids settling. However, in the majority of calculations it is overly conservative to assume weighted fluid on the load side of the tubular and unweighted fluid on the back-up side of the tubular. If these additional investigations demonstrate that casing strings are susceptible to APB-induced failure, the following mitigation design principles shall apply: • Barring extenuating operational circumstances, two mitigators will be designed for each annulus of concern. This design approach instills the necessary amount of redundancy in the mitigation plan. Examples of acceptable, two-mitigator combinations include rupture disks with a nitrified foam spacer, rupture disks with syntactic foam and vacuum-insulated tubing (VIT) with rupture disks. • In a given annulus, each mitigator must stand on its own. In other words, the APB-reduction benefit of one mitigator cannot depend upon the operation of another mitigator. • Mitigation design must consider the overall mitigation strategy for the well in question. Circumstances may arise where the activation of one mitigator may adversely impact the functionality of another mitigator. An example of such a scenario would be the activation of syntactic foam, which lowers the collapse back-up for the outer string in the annulus. If rupture disks are employed in the next outward string, their design must incorporate the lower collapse back-up pressure potentially induced by the syntactic foam. 1 The
tubing by production casing annulus is vented on almost all wells; the outermost casing string’s annulus will be exposed to formation and, therefore, be limited in the annular pressure build-up it can sustain prior to formation fracture. 2 An
exception would be an A annulus that is known to be accessible and vented.
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Figure 15.3. Sealed Annuli
• The target design factor will be mitigator-dependent. Each mitigator possesses unique design and implementation considerations that may alter the target safety factor. For example, if there is concern that wellbore conditions might compromise the placement of a nitrified foam spacer, then an additional foam volume may be recommended to compensate for nitrogen lost to the formation, thereby effectively increasing the design factor above the standard 1.1 multiplier. A specialist within EPT should be consulted before undertaking mitigation design. As a final note, the Engineering Technical Practice for Casing and Tubing Design requires that all wells “having sealed or potentially sealed inaccessible annuli” be subject to EPT review.
15.2.2
Demonstration of Fundamental APB Mechanism
Consider a relatively incompressible fluid completely filling a closed container. If the temperature of the fluid is increased, it will attempt to expand in accordance with its coefficient of thermal expansion. This volume change will be countered by the rigidity of the container. Resistance to the free expansion of the fluid induces a pressure increase. According to the rigidity of the enclosing walls, this pressure increase induces a corresponding change in the dimensions of the container. An equilibrium ensues involving changes in both the fluid and the container. The incremental annular pressure accompanying a change in temperature is, therefore, a function of the mechanical and thermal properties of the annular fluid, the flexibility of the confining boundary and the amount of temperature increase. The following is a simplified method for determining pressure increases in sealed annuli due to temperature increases. This model is for illustrative purposes and should not be used in actual well design. For well design, APB calculations using appropriate software, such as Wellcat, is in order. EPT Drilling
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Figure 15.3 displays the annuli with letters, starting with the “A” annulus as the annulus outside the production tubing. The incremental pressure due to thermal effects in the “B” annulus (13-3/8 in. × 95/8 in.) is3 ∆pann =
Σ∆V Sum of unconstrained volume changes = , Σf Sum of system flexibility
(15.3)
where Σ∆V is the overall volume change of the annulus given by Σ∆V = ∆V2 + ∆Vann + ∆V3 ,
(15.4)
where ∆Vi is the volume change due to expansion/contraction of the ith casing string, and ∆Vann is the volume change of the annular fluid. For Casing 2 in Figure 15.3, π 2 ∆V2 = − L2 D2 αT 2 ∆T 2 , 2
(15.5)
where D2 indicates the average or mid-surface diameter and second order terms in diameter change are ignored. The sign convention in Equation 15.5 indicates that the expansion of Casing 2 will increase the overall volume and reduce the APB pressure. If Casing 2 is a tapered string, then ∆V2 =
−Σni=1
π i i2 i L D αT 2 ∆T 2 , 2 2 2
(15.6)
where the summation is taken over all of the n sections of the tapered string above the TOC. For the annulus fluid, ∆Vann = Vann αT V ann ∆T ann .
(15.7)
For a casing with a single outside and inside diameter, π 2 d2 − D32 Lann αT V ann ∆T ann , 4 is the length of the annulus to the TOC. ∆Vann =
where Lann
(15.8)
For Casing 3 in Figure 15.3, π 2 L3 D3 αT 3 ∆T 3 . (15.9) 2 The sign convention in Equation 15.9 indicates that the expansion of Casing 3 will decrease the overall ∆V3 =
volume and increase the APB pressure. The denominator in Equation 15.3 is determined as the sum of the component terms. For Casing 2, 3
f2 =
πL2 D2 , 4Et2
(15.10)
with f2 for tapered strings calculated by 3 This
approximate method assumes no pressure changes in annuli “A” and “C”.
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f2 =
3 i i n πL2 D 2 Σi=1 , 4Eti2
(15.11)
where the summation is taken over all of the n sections of the tapered string above the TOC. For the annulus, fann = Vann Cann ,
(15.12)
or, for uniform casings, fann = For Casing 3,
π Lann Cann d22 − D32 . 4
(15.13)
3
πL3 D3 f3 = . 4Et3
15.2.3
(15.14)
Example
A subsea completion (mudline at 500 ft) has an annulus with 9-5/8 in. 47 lb/ft N80 casing (top-of-cement 7,000 ft) interior and 13-3/8 in. 68 lb/ft N80 casing (top-of-cement at 5,000 ft) exterior. The fluid in the 95/8 × 13-3/8 in. annulus is 11.0 ppg OBM. The average temperature changes are, respectively, ∆T 2 = 65◦ F, ∆T 3 = 72◦ F, ∆T ann = 70◦ F. Compute the incremental pressure due to temperature change. From Equation 15.3 ∆pann =
Σ∆V ∆V2 + ∆Vann + ∆V3 = , Σf f2 + fann + f3
(15.15)
where (see Equations 15.5, 15.9 and 15.7),
∆V2 = −
π [(5, 000 − 500) × 12] 2
π ∆V3 = [(7, 000 − 500) × 12] 2
∆Vann =
13.375 + 12.415 2
9.625 + 8.681 2
2
2
6.67 × 10−6 (65) = −6, 083 in3 , 6.67 × 10−6 (72) = 4, 735 in3 ,
(15.16)
(15.17)
π 12.4152 − 9.6252 [(7, 000 − 500) × 12] 3.64 × 10−4 (70) = 95, 935 in3 , 4
(15.18)
where αT V ann is taken from Table 15.1 at 2,000 psi and 100◦ F (midsection pressure and temperature). Combination of Equations 15.10, 15.14 and 15.13 yields π [(5, 000 − 500) × 12] 13.375+12.415 2 f2 = 4 × 30 × 106 × 13.375−12.415 2 π [(7, 000 − 500) × 12] 9.625+8.681 2 f3 = 4 × 30 × 106 × 9.625−8.681 2 EPT Drilling
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3
3
= 6.28 in5 /lb,
= 3.32 in5 /lb,
(15.19)
(15.20) BP Confidential
Table 15.1. Thermal Expansivity (10−4 / [◦ F] ) Oil Base Mud - 11.0 ppg (1.32 SG)(80/20 OWR)
a
Water Base Mud - 12.0 ppg (1.44 SG)
psiaa
100◦ F
200◦F
150◦F
200◦ F
15
3.88
4.41
3.06
3.65
2,000
3.64
3.99
3.04
3.60
5,000
3.36
3.53
2.98
3.50
10,000
3.04
3.09
2.90
3.35
Used midpoint pressure and temperature to determine the appropriate expansivity values.
π [(7, 000 − 500) × 12] × 4.22 × 10−6 × 12.4152 − 9.6252 = 15.88 in5 /lb, (15.21) 4 where Cann is taken from Table 15.2 with midpoint pressure ((3, 500)(11.0)(0.052) = 2, 000 psi) and temperature 100◦ F. fann =
Substitution of Equations 15.16–15.21 into 15.15 yields −6, 083 + 95, 935 + 4, 735 = 3, 712 psi. (15.22) 6.28 + 15.88 + 3.32 Upon review of the example calculation, the importance of properly defining fluid properties is apparent. ∆pann =
Because of the sensitivity of APB calculations to fluid properties, it is highly recommended that all APB calculations be conducted with a tool such as Wellcat wherein detailed tabulation of fluids properties is an integral part of the software model.
15.2.4
APB Mitigation
Should the predicted APB pressure be so high that conventional tubular design considerations cannot ensure well integrity, a number of tools have been developed to mitigate APB effects. As summarized in Table 15.3, APB mitigation tools can be categorized by their effect on the causes of APB–fluid properties, annulus flexibility and driving force (temperature change). Of the mitigation tools listed in Table 15.3, several have achieved a level of application as to require further comment. The state of APB mitigation design, however, is such that a specialist should be consulted. 15.2.4.1
Nitrified Foam Spacer
Nitrogen can be an effective means of reducing Annular Pressure Buildup (APB) by increasing the compressibility of the overall fluid column. The pressure required to compress nitrogen is an order of magnitude lower than that required to compress drilling fluids. The primary means of introducing nitrogen behind casing strings is through a nitrified spacer pumped as a stage in a primary cement job. Design and placement of the nitrified spacer is a common operation. However, not all annuli can be protected with nitrogen due to gas migration issues. EPT Drilling
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Table 15.2. Compressibility of Muds Oil Base Mud - 11.0 ppg (1.32 SG)(80/20 OWR) Pressure, psia
Density, ppg
Compressibility, 10−6 /psi
Density, ppg
Compressibility, 10−6 /psi
15
10.94
4.66
10.5
4.64
2,000
11.04
4.22
10.6
5.63
5,000
11.17
3.64
10.8
4.62
7,000
11.24
3.31
10.9
4.09
10,000
11.35
2.89
11.0
3.49
Water Base Mud - 12.0 ppg (1.44 SG) Pressure, psia
Density, ppg
Compressibility,
Density, ppg
10−6 /psi
Compressibility, 10−6 /psi
15
11.00
2.45
11.0
2.65
2,000
11.00
2.40
11.0
2.58
5,000
11.00
2.26
11.0
2.43
7,000
11.00
2.18
11.0
2.32
10,000
11.00
2.04
11.0
2.18
15.2.4.1.1 Benefits of a Nitrogen Cushion APB increases with temperature according to the following simplified relation,
pAP B ∼ αV T Kf ∆T ,
(15.23)
where ∆T is the average change in temperature from the initial state where the annulus is sealed. Both αV T and Kf are dependent on pressure and temperature. A lower bulk modulus equates to a more compressible fluid and a lower APB. Drilling fluids are relatively incompressible. It takes 3,500 psi to compress water 1% by volume, 2,500 psi to compress diesel 1%, and 2,000 psi to compress a typical synthetic base fluid 1%. By comparison, nitrogen gas at 2,000 psi compresses 1% by volume with less than 25 psi additional pressure. Introducing nitrogen into an annular space significantly reduces the combined fluid bulk modulus, thereby lowering APB. The nitrogen acts as an accumulator, maintaining a more constant pressure as it assumes most of the volumetric fluid change due to thermal expansion and contraction of the mud. The bulk modulus for a composite column of gas and liquid is determined by the volumetric average of the fluid compressibilities, where compressibility is the reciprocal of bulk modulus EPT Drilling
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Table 15.3. APB Mitigation Tools Effect
Tool
Comment
Brute Force
Thick-walled casing
Particularly in wet tree completions, the combination of multiple casing strings and limited geometric clearances–a space of between approximately 9-1/2 in. (SSSV diameter) and 18-3/4 in. (bore of high pressure wellhead) render this solution impractical.
Foam spacer Fluid Properties
Fluids with low dp/dT Cement the entire annulus
Although theoretically possible, attempting this solution is extremely dangerous, and not recommended. Any shortfall will occur near the top of the annulus where the average temperature change, and, therefore, APB incremental pressure, can be expected to be highest.
Vent the annulus Annulus Flexibility
Possible venting alternatives include: •
Providing an active path to the surface, as in the annuli on an onshore or a platform well, or, usually, the A annulus on subsea completions;
•
Installing a pressure relief mechanism:
–
Formation fracture (leaving the top of cement below the previous shoe); however, see the design principle above regarding solids settling;
Allowing communication between annuli
–
Rupture disks;
–
Grooved casing, essentially an alternate form of rupture disk, where the casing wall is milled to a precise value to ensure rupture within a narrow range of differential pressures.
In some instances combining two annuli into a single annulus can lower the incremental thermal pressure.
Syntactic foam Avoiding trapped pressures external to the target annulus
The intent here is to avoid the undesirable additional stiffening of an annulus boundary by pressure build-up in an adjacent annulus.
Vacuum Insulated Tubing (VIT) Nitrogen blanket
low pressure nitrogen in, for example, the A annulus acts as an insulator in conveying heat to outer, more vulnerable annuli. As the nitrogen pressure increases, the ensuing increase in conductivity lowers the effectiveness of the nitrogen as an insulator. A nitrogen pressure of 100 psi or less is recommended.
Driving Force Gelled brine
Gelled brine is usually employed in conjunction with VIT. The large heat loss at the VIT connection can be substantially contained by the gel. In the absence of gel, heat loss at a VIT connection reduces both the density and the viscosity of the A annulus fluid, promoting natural convection behind the vacuum chamber, thus partially defeating the purpose for which the VIT was installed.
Connection leak integrity
Leak of a connection can relieve APB in an adjacent annulus. However, depending on a loss of connection leak integrity to mitigate APB is not recommended. Further, the in-service leak of a connection would be both difficult to verify and to control.
Avoiding unnecessary initial annulus pressure
Particularly for subsea wellheads, if a pressure-from-above is used to set a seal assembly, some of the setting pressure can leak by the seal in the setting process and impose an undesirable increment to the initial pressure in the annulus. This additional initial pressure will add to any subsequent incremental APB, and should be avoided.
Kcomp =
Vg Vg Kg
+ Vl +
Vl Kl
.
(15.24)
A small volume of gas has a significant impact on the composite bulk modulus, as well as the level of APB. For example, Table 15.4 shows simplified calculations that demonstrate the impact of adding nitrogen to an annular space. The casing strings in the example are assumed to be perfectly rigid, and thermal expansion of the steel is neglected. Without nitrogen, the mud thermally expands 15.5 bbl. Compressing this volume to fit within the original annular space results in 10,817 psi APB. When 27 bbl of nitrogen (at 2,500 psi mudline pressure) are introduced, the nitrogen thermally expands 6.7 bbl and the mud expands 15.4 bbl. The combined 22.1 bbl of fluid are compressed to fit within the original annular space, but with a composite bulk modulus much lower than that for the mud alone. The nitrogen gas lowers APB to 3,186 psi, a 70% reduction, while occupying only 5% of the total annular volume. EPT Drilling
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Table 15.4. Simplified Nitrogen Gas Cap Example 13-5/8 in. 88.2 lb/ft × 9-7/8 in. 62.8 lb/ft Annulus TVD, ft
Volume, bbls
5,000
Ti , ◦ F
Tf , ◦ F
40
230
27.0 5,500
155 110
230
513.3 15,000 Total
∆T , ◦ F
75 200
230
540.4
79
Case 1: All Water Base Mud TVD, ft
αa , 1/◦ F
Expansion, bbls
K a , psi
0.00038
1.6
365,000
0.00036
13.9
379,000
15.5
378,275
10,817
αa , 1/◦ F
Expansion, bbls
K a , psi
∆p, psi
0.0016
6.7
5,000
0.0004
15.4
335,000
22.1
77,907
∆p, psi
5,000
5,500
15,000 Total Case 2: 500 ft of Nitrogen at 2,500 psi TVD, ft 5,000
5,500
15,000 Total a
3,186
α and K are calculated at the average p and T for the interval at final conditions.
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15.2.4.1.2
Mud Removal and Channeling during Placement The primary method of placing nitrogen
in the annulus is by foaming it into a spacer and circulating the mixture ahead of a cement job. Design of the spacer is critical, as it must remove mud from the hole, maintain proper hydrostatic pressure for well control, carry adequate nitrogen to mitigate APB and remain stable without gas breakout for several days. The spacer base fluid is designed to be compatible with other wellbore fluids and to achieve the hole cleaning and hydrostatic pressure requirements. A volume of base spacer containing the proper surfactants should be pumped ahead of any nitrified spacer to ensure stabilization of the nitrified spacer with the drilling fluid. This volume should be determined from the effective interface geometries. The nitrogen is then added to the remaining spacer as it is pumped. There are two different techniques in placement of a nitrified spacer. The spacer may be placed via direct circulation of the spacer ahead of the primary cementing operations or as a remedial operation placed in a bullhead manner directly into the annulus in question. If a conventional (non-foamed) cement job is planned, an additional volume of spacer may be required to separate the nitrified spacer from the primary cement stage. There are advantages to foaming the lead cement with the same nitrogen level as the foamed spacer. The primary reason is nitrogen compressibility. As the foamed spacer is pumped down hole, increasing hydrostatic pressure causes the nitrogen to compress and the overall spacer density to increase. Similarly, once the spacer turns the corner and flows up the annulus, the decreasing pressure causes the nitrogen to expand and the spacer density to decrease. The dynamics of this process create a density imbalance with non-foamed cement and cause displacement problems. Foaming the cement removes this imbalance as the cement compresses with the spacer. Alternately, an additional fluid spacer may be pumped to separate the foamed spacer from conventional cement. The presence of nitrogen in the spacer places an even greater priority on hole conditioning. The mud must be in good shape to enable uniform displacement and removal. Otherwise, channels of nitrified spacer may bypass the mud and circulate much higher in the annulus than designed. If a weak shoe prevents the nitrified spacer from circulating into the annular space (or if gas migration is a large concern, see Section 15.2.4.1.4), then it is injected down the backside of the casing. This method assumes the shoe of the previous casing is open so that the spacer can squeeze mud from the annulus into the formation below. If present, the seal assembly is removed and the wellhead is flushed clean. A new seal assembly is run to the hanger, and then nitrified spacer is injected into the annulus before the seals are set. The technique of placing the nitrified spacer into the annulus via the seal assembly can reduce the impact of migration of higher pressure gas from affecting APB in the annulus. The distance of the spacer from the mudline is designed on an individual basis, and no set distance is created in the design criteria. 15.2.4.1.3
Foam Stability and Testing One of the requirements for the nitrified foam spacer is stability
of the gas suspension. The spacer should remain stable for a period of time in which remedial operations can be undertaken to re-set a seal assembly in deep water if the initial attempt to set the seal fails. This time will vary with depth of water and wellhead design. This requirement prevents gas from migrating before wellhead seals are set, including additional time for several trips to remedy unforeseen events. Foam qualities above 30% tend to become instable more quickly, so quality should be limited to 25 to 30%4 . 4 Simple
stability checks are performed at atmospheric pressure by placing the spacer in a beaker and observing the liquid level. A drop in fluid level over time indicates gas breakout and an unstable spacer. The test can be performed at elevated
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Halliburton has performed physical tests to study the effectiveness of their spacer design. A non-foamed fluid is placed in a test chamber at initial wellbore temperature and pressure. The temperature is increased to producing conditions and the pressure buildup is recorded. The sequence is repeated for several foam qualities to determine a curve of APB as a function of the percent volume of foam in the annulus. This curve can be used to verify the required nitrogen volume that sufficiently reduces pressure buildup. The steps below illustrate the design of a nitrified spacer. These steps are general and may vary with the implementation of new testing techniques and new technology. The relevant service provider should be contacted to ensure adherence to current best practices. Temperature Determination. Accurately determining initial temperatures and the temperatures to which an annulus will be subjected over the life of the well requires the use of software tools such as Wellcat. These predictions should take into account the installation of the well and all associated operations therein. The initial conditions that exist will be dictated by the drilling times, the circulation, retest times and the placement of the primary cementing operations. Once established in the design phase of the project, this prediction model must be carried through the execution stage of the project. Unforeseen well activity could effectively change the initial temperature conditions for APB. Once initial thermal conditions (prior to production) are determined, the maximum temperature should be determined. This temperature profile can be established from production rates and bottom hole static temperatures for an area of development (see also Section 15.2.1). Spacer Volume Determination. Once the temperature boundaries have been determined, the nitrified spacer volume design can begin. Historical data shows an annulus with an effective 5% volume of nitrogen is often sufficient to prevent APB from failing a wellbore. However, every case is unique and should be examined accordingly. First, the effected volume in the trapped annulus must be determined. If an annulus is to be sealed then top of cement becomes the lower boundary. Upper boundaries are most likely determined by the depth of the seal assembly in the case of a subsea casing string or a liner hanger. Once the boundaries are determined, the volume can be calculated. Testing through the remainder of the spacer testing will always refer back to this initial volume. Nitrogen Volume Determination. Wellcat may be used in most design cases; however, Wellcat may be backed up by physical modeling for critical cases. A thick-walled test chamber such as an autoclave can be used for APB testing. Although this test chamber is not perfectly rigid, the technique is still effective for APB determination. The drilling fluid which will exist in the annulus must be sought for testing purposes. Initial tests should determine the severity of the APB as it relates to the particular fluid(s) to be left in the trapped annulus. The base fluid should be placed in the test chamber, and the vessel and the fluid brought to initial temperature conditions at atmospheric pressure. Once the vessel and fluid have been brought to the initial conditions, the vessel should be sealed and an initial pressure be placed on the fluid. As a minimum, the pressure at which the fluid will exist in the wellbore can be used; however, 2,000 psi can be used as an arbitrary starting point if the pressure at which the fluid will exist, including the expected pressure build-up, is greater than the rating of the test vessel. The system should then be ramped to the final temperature condition recording pressure build-up as a function of temperature. This test will be the baseline for the annulus fluid. Once the baseline test is complete, spacer design may begin. pressures using a vessel with a sight glass.
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In the design of the spacer, several factors must be taken into account. The spacer must be an effective mud removal spacer whether the spacer is injected through the annulus or placed with the primary cementing operations. Logistics should be taken into account. Necessary pit volume for spacer should be determined. If insufficient pit space is available, provisions for additional tank space may be necessary. Blenders may be used to supplement volume for mixing and storing spacer for a job. The maximum effective quality of the spacer should not exceed a given percent. This maximum quality is dependent upon many factors and may be different depending upon which service company performs the work. Testing of the spacer should begin with compatibility testing with the drilling fluids that will be displaced. In the case of synthetic fluids, water-wetting testing should be conducted and surfactant packages determined from the testing. Once all compatibility testing is complete with the drilling fluid, testing should be conducted with the lead portion of the cement. Thickening time testing should be run to ensure that the surfactant package does not affect the cement design. If the spacer passes these tests, the ability of the spacer to remain stable with a foaming surfactant must be performed. Using the designed spacer, foaming surfactants should be added, and a surface atmospheric stability test performed. Each service company should have guidelines on a pass/fail test for surface stability. Once the spacer stability has been ensured with the foaming surfactant, all compatibility tests should be repeated to ensure the foaming surfactants do not affect compatibility with the wellbore fluids and compatibility with the primary cement. Stability time requirements may take several days to effectively test, and time should be allowed for several iterations of this testing. Therefore, if a time period of 72 hours is required for the spacer to remain stable, several weeks may be necessary for testing. In addition, spacers may act differently under pressure. Stability can be affected by temperature and pressure; therefore, final conditions may (in some cases) be tested for. This testing is difficult to perform, and should be coordinated with the service company representative. Once a spacer design has been made, testing of the final quality of the system can be performed. The fluids should be placed into the test chamber in the same ratios as they would exist in the wellbore. First, the wellbore fluid should be placed in the chamber. The liquid portion of the spacer to be used should then be added. The remainder of the test chamber should be filled with nitrogen. Since the test will be pressured with nitrogen, the volume from the valve of the test chamber to the inlet should be added to the total volume of the system. The fluids should be brought to the initial conditions as outlined in the temperature determination. The system should then be sealed and nitrogen used to pressure the test chamber to the initial pressure. The temperature can now be ramped to final temperature conditions, recording the pressure as a function of temperature. Various concentrations of spacer and nitrogen should be tested to determine the minimum effective volume of nitrogen to mitigate APB. This number should then be increased by a safety factor to determine the final design of the nitrified spacer to be placed in the annulus. 15.2.4.1.4 Gas Mitration After the nitrified foam spacer has been stagnant in the wellbore for some time, the microscopic bubbles may eventually coalesce and rise to the mudline. Using the ideal gas law, the change in bubble pressure is ps Vs Tml , (15.25) Ts Vml where ()s denotes the conditions at the placement depth. If the annular space is sealed, there is effectively no pml =
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room for the gas to expand as it rises, so Vs = Vml . If the difference in (absolute) temperature is small, the gas remains at constant pressure as it rises. The bubble migrates bottomhole pressure back to the mudline, which in turn acts on the hydrostatic mud column to elevate pressures for the entire annulus. The impact of gas migration can outweigh the benefits of a gas cushion for wells with high mud weight or long annuli. This occurs if the increase in mudline pressure due to gas migration is greater than the decrease in APB due to gas compressibility. A potential remedy is to circulate the nitrified foam spacer well ahead of the cement with a long interval of unfoamed spacer in between, which lowers the initial nitrogen pressure at placement. A second option is to bullhead spacer down the annulus after the string is cemented; however, this option requires the shoe to be open and a leak-off path to be present. This approach of calculating gas migration with full bottomhole pressure is slightly conservative, as it neglects flexibility of tubulars. As the annular pressure increases, the adjacent tubulars will slightly deform according to the Lam´e equations, resulting in a larger annular space for the bubble to occupy and a correspondingly lower pressure. Additionally, the change in temperature can significantly reduce the bubble pressure for a long annulus. 15.2.4.1.5 Risks of Nitrogen Placement BP has experienced at least two incidents where a nitrified spacer was circulated back into the drilling riser. In the first instance, the well had complete loss of circulation prior to pumping the cement job. This prevented standard hole cleaning and mud conditioning and likely led to channeling during the cement job. A nitrified foam spacer was displaced ahead of the cement with partial returns. After the job, a large volume of mud returned to the rig floor, causing great concern for well control. The source of the flow was due to a portion of the nitrified spacer circulating past the hanger seals and entering the drilling riser. The nitrogen then rose and expanded, displacing mud as it returned to the surface. The second instance occurred on a 13-5/8 in. primary cement job with foamed spacer and foamed lead cement. The designed spacer top was 2,434 ft below the mudline. Mud was lost while running casing, and almost the entire cement job was pumped without returns. Returns of 30% were observed during the final 100 bbl of displacement, and the seal assembly was set shortly after bumping the plug. Returns flowed at 3 to 4 bbl/min, and the annular was shut. Nitrogen broke out at the surface and discharged synthetic mud on the rig floor and shaker room. To fill the riser, 200 bbl of mud were required. Both of these incidents underscore the risk of pumping nitrified spacer with poor hole conditions. If the spacer is ineffective at cleaning the hole, channeling can result in portions of the nitrified spacer returning much higher than planned. In any operation where nitrified fluids are used to enhance a spacer for the purpose of APB mitigation or enhanced mud removal, contingencies should always be in place to handle nitrogen enhanced fluids back to surface. Current rig equipment can effectively mitigate the risk to a manageable level to ensure no HSE risks. Service companies involved with the operations should provide a plan for nitrified fluids to surface, and rig contractors should be an integral part of the plan. 15.2.4.1.6 Calculation Procedures The calculation procedure for nitrified spacers circulated ahead of cement is as follows: • The average pressure of the nitrified spacer is calculated using the hydrostatic column of mud plus half of the hydrostatic column of spacer. EPT Drilling
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Figure 15.4. Gas Migration Calculation Procedure
• This pressure is assumed to migrate to the mudline due to nitrogen gas liberating from the compressible spacer. The volume and density of the nitrogen bubble is included in finding the mudline pressure. • Since the system is closed, the full gas pressure now acts on the column of mud. This assumes that the gas does not have room to expand and, thus, occupies the same volume. • APB is calculated as a function of nitrogen volume using WellCat or a similar tool. • The resulting APB is superimposed on the column of pressurized mud. The length of the spacer decreases and its gradient increases to account for the liberated nitrogen, now residing at the top of the column. Figure 15.4 is a graphical depiction of calculating the pressure profile with gas migration. The final pressure profile is determined from the initial nitrified spacer pressure, calculated APB, and the hydrostatic column of mud and spacer. Relevant equations are included Section 15.2.4.1.6.1. 15.2.4.1.6.1
Gas Migration Calculations The average pressure in the spacer is determined by the
hydrostatic mud weight down to the top of the spacer, plus half of the hydrostatic pressure of the spacer, as 1 ps = hm γm + hs γs . 2
(15.26)
The height of the spacer is the volume of the spacer divided by the annular capacity. The spacer volume is written in terms of the desired gas volume and the foam quality of the spacer as hs = EPT Drilling
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(15.27) BP Confidential
Substitution of Equation 15.26 into 15.27 yields ps =
hm γm +
Vg γs 2 × annular capacity × foam quality
.
(15.28)
The ideal gas law is used to find the nitrogen pressure after migration. Assuming there is no change in the annular volume and noting that mud compressibility is much less than gas compressibility, the gas volume does not change as it coalesces and rises. Thus, the change in pressure is related to the change in temperature as the bubble rises, pg = ps
Tg , Ts
(15.29)
where Tg and Ts are in this instance absolute temperatures (◦ R = ◦ F + 459.67). Combination of terms yields Tg pg = Ts
hm γm +
Vg γs 2 × annular capacity × foam quality
.
(15.30)
Once the pressure of the bubble is known, the additional APB is superimposed to find the total mudline pressure. This is then added to the fluid column to determine the pressure profile. Since the pressure of the bubble is defined as the average pressure, the pressure at the mudline is found by subtracting half of the bubble hydrostatic pressure, pml = pg + pAP B −
Vg γg . 2 × annular capacity
(15.31)
The remaining pressures in the annulus are calculated from the mudline pressure and the hydrostatic column of fluids. The spacer height and density no longer include the entrained nitrogen and are affected accordingly, hs(basef luid)
Vg = annular capacity
1 −1 , foam quality
(15.32)
γs = foam quality × γg + (1 − foam quality) × γs(basef luid) ,
(15.33)
and, therefore, γs(basef luid) =
γs − foam quality × γg . 1 − foam quality
(15.34)
The density of nitrogen gas at pressure and (absolute) temperature is found from gas tables or from compressibility equations of state. A simplified relation based on the Soave-Redlich-Kwong (SRK) equation of state [88] is provided here for reference, where the density γg is in ppg, temperature T is in ◦ R and pressure p is in psi. It is accurate within 5% for pressures ≥ 500 psi,
γg = 6.22 × 10−11 T − 5.94 × 10−8 p2 + −1.09 × 10−6 T + 1.26 × 10−3 p + 1.21 × 10−5 T. EPT Drilling
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15.2.4.1.6.2
Alternate Post-Installation Scenarios The calculations of Section 15.2.4.1.6.1 reflect
only one of a variety of scenarios one might envision for the post-installation behavior of the nitrogen spacer. The nitrogen bubbles may subsequently coalesce and rise in the annulus, or they may never break out of the spacer. Although not an exhaustive list, Figure 15.5 describes four different design scenarios to illustrate what might happen to nitrogen after initial placement, Scenario 1 being that described in the calculations of Section 15.2.4.1.6.1: 1. The nitrogen coalesces and rises. If the annulus is closed, there is little room for volumetric expansion, resulting in a constant nitrogen density. Pressure change is due to temperature change only, thereby migrating near-bottom hole pressure back to the mudline. APB is calculated assuming a closed shoe and high pressure nitrogen. This scenario often results in the worst case as a higher initial pressure is communicated to the mudline than in other scenarios, and nitrogen compressibility is diminished as pressure increases. 2. The nitrogen coalesces and rises; however, the annulus is not sealed. As the nitrogen rises, the overall fluid column equalizes with the lowest exposed fracture gradient. The shoe bridges after the nitrogen bubble rises. APB is calculated assuming a closed shoe and lower pressure nitrogen than in the first scenario. This case is more realistic when the nitrified spacer is placed inside the previous casing or possibly within a salt formation. 3. The nitrogen does not break out of the spacer. APB is calculated using the default WellCat assumptions of nitrogen at hydrostatic mud pressure and an impermeable formation interface. For Figure 15.5, the assumption is a bridge near the base of salt and an artificially high salt frac gradient. 4. No nitrogen enters the cased hole annulus. Either the foamed spacer leaks off during the cement job or the nitrogen bleeds to the formation as it coalesces and rises. APB calculations reflect no nitrogen and a closed shoe. Other scenarios could exist. Likewise, intermediate points between two extremes could occur, such as a portion of the nitrogen reaching the cased hole annulus. Nevertheless, consideration of the above four scenarios in Figure 15.5 offers perspective on the complexity of design involving mitigation of APB with nitrogen. 15.2.4.2
Rupture Disks
Rupture disks are one-time pressure relief devices to limit APB. Although rupture disk technology has been established for decades, the use of disks in oilfield casings is a relatively new and novel application. This section summarizes information that supports the use of rupture disks for APB abatement and provides guidance on the selection and installation of such devices. 15.2.4.2.1
Relation to APB In the event that APB cannot be mitigated by alternate measures (e.g.,
keeping the shoe open to promote pressure bleed-off, placing crushable syntactic foam modules that allow fluid expansion or spotting nitrogen in the annulus that compresses and effectively regulates pressure changes), it is imperative the casing fails outward (i.e., burst rather than collapse). A pipe rupture or connection leak EPT Drilling
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gas cap
Scenario I Nitrogen coalesces Bubble rises with constant density no volume change pressure change due to temperature change only Shoe closes, forming trapped annulus
Placed Nitrified Spacer ML @ 6,157’
Scenario II Nitrogen coalesces Bubble rises with freedom to expand pressure regulated by FG at the shoe or the base of salt Shoe closes, forming trapped annulus
spacer without nitrogen
Top of Spacer @ 8,211’ 20” @ 9,367’ Bottom of Spacer @ 10,069’ Salt from 8,603’ to 11,354’ TOC @ 12,500’
16” @ 14,588’
Scenario III
Scenario IV
Foam remains stable Shoe remains open APB calculations reflect infinite salt FG
Nitrogen coalesces Bubble rises and leaks to the formation or nitrogen leaks off during placement Shoe closes, forming trapped annulus
“sealed” borehole through salt
All depths assume gauge 20” under-reamed hole and full returns. No returns were observed during the cement job.
Figure 15.5. Design Scenarios for Post-Installation Nitrogen Behavior (Example from Typical Thunder Horse Design)
likely results in minor fluid loss to the formation and no adverse impact to production integrity. However, a pipe collapse potentially leads to cascading failures of inner strings and loss of the well. Thus, wells susceptible to APB should be designed so outer string burst resistances are lower than inner string collapse resistances. Consider the wellbore in Figure 15.6. The API minimum internal yield pressure (MIYP) rating for the 20 in. casing is 3,060 psi, while the 16 in. API minimum collapse rating is 3,470 psi. Based on these ratings, high pressures in the 16 in. × 20 in. annulus will “rupture” the 20 in. before collapsing the 16 in., all other things being equal. This neglects the impact of fluid densities and pressures outside the 20 in. and inside the 16 in. The pipe ratings seem to indicate that a failure would occur outward, thereby protecting the integrity of the flow stream. A review of the origin of the API ratings exposes the flaw in this logic. The MIYP rating is a simplified equation to calculate the pressure that results in the onset of yield, assuming the actual yield strength is equal to the minimum acceptable value. It does not predict the pressure level where the pipe ruptures or loses pressure integrity (see Chapter 9). The actual rupture strength of the pipe may be 50% higher than MIYP; the exact value depends on grade and dimensional tolerances. Similarly, the API collapse rating is based on a historical database of collapse tests and reflects a reliability of 5 failures out of 1,000 (see Chapter 8). The actual collapse resistance should exceed the API rating 99.5% of the time. Furthermore, modern manufacturing practices may also enhance collapse resistance. Thus, comparison of the outer string MIYP rating to the inner string collapse rating does not indicate direction of pressure failure with any measure of confidence. The design process is further complicated by uncertainty in the actual dimensional and mechanical properties of a length of casing. Figure 15.7 illustrates this situation. The vertical lines represent the EPT Drilling
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Figure 15.6. Example Wellbore
specified, deterministic ratings for two strings of pipe, where the 16 in. is expected to be stronger in collapse than the 20 in. is in burst. These specified ratings indicate a pressure breach occurs through the 20 in., away from the wellbore. However, the actual 20 in. burst pressure falls anywhere within a distribution of values depending on the ranges of yield strengths and wall thicknesses in the pipe order (see Chapter 16). Similarly, there are variations in the true collapse resistance of the 16 in. There can be a region in these two distributions where the 16 in. collapse is weaker than the 20 in. burst, even though the specified ratings indicate otherwise. A rupture disk is a one-time pressure relief device that is used to set the failure point of the outer casing string with a high degree of accuracy. The disk is specified to rupture at the casings MIYP (or slightly above), thereby controlling the pressure and direction of an APB induced failure. Ideally, the disk is invisible to the casing during drilling operations and fails under production conditions to protect the inner string from collapse pressures. 15.2.4.2.2 Rupture Disk Technology Rupture disks have been used as one-time pressure relief valves for over 80 years. Typical applications are in chemical processing plants where the disks vent to relief pipelines, though the technology has also found its way into aerospace and industrial usage. Figure 15.8 shows a common processing plant disk. The bulged surface allows for higher operating pressures than with flat disks, where the operating pressure is the limit that the disk withstands before rupture pressure is altered due to deformation or excessive yielding. Disks are designed to have operating pressures as high as 90% of the rupture pressure (e.g., a 3,000 psi rupture disk contains 2,700 psi on the concave side of the disk without EPT Drilling
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Figure 15.7. Uncertainty in Performance Properties
Figure 15.8. Rupture Disk for Processing Plants
changing its failure point). Figure 15.9 shows a rupture disk for downhole application. The bulged rupture membrane is interior to the disk and is not visible in the figure. A downhole disk is normally installed either in a specifically designed APB sub that resembles a long coupling. 15.2.4.2.3 Testing for Downhole Application - Outward-acting Rupture Disks Downhole application of rupture disks presents a unique environment that deserves special attention. Back pressure associated with annular fluids is significantly higher than the near atmospheric conditions on the backside of common plant EPT Drilling
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Figure 15.9. Rupture Disk for Tubulars
applications, and the disk may be required to hold collapse pressures equal to the pipe rating. Working pressure cycles are also important, as the casing may be stressed several times during drilling operations. The rupture disk may be placed in a cemented section of casing, so the impact of cement outside the disk must be understood. EPT has tested outward-acting rupture disks in several aspects [16]: • Pressure test to failure (straight rupture), illustrating the consistency of rupture disk performance5 ; • Backup test to failure (collapse), illustrating that outward-acting rupture disks will not fail below their rated pressure when loaded by an external pressure differential; • Pressure test while holding backup pressure6 ; • Cycle internal pressure, increasing to failure7,8 . 5 In
tests conducted on outward-acting rupture disks in a Hunting BOSS connection fixture, and with disks rated at 5,100 psi, the first disk ruptured at 5,150 psi and the second disk failed at 5,134 psi, both within 1% of the specified rating. In elevated temperature tests with disk rated at 10,317 psi at 150◦ F, the two disks failed at 10,330 psi and 10,370 psi, or within 1/2% of the nominal rating. 6 Two disks were pressure tested to failure while holding 3,000 psi backup pressure at ambient temperature. The first failed at 13,910 psi and the second ruptured at 13,750 psi. Differential pressures were 3.1% and 1.6% above the nominal 10,582 psi rating at 72◦ F. 7 Pressure was held for 10 minutes at 50%, 70%, 80% and 90% of the nominal rupture rating with complete pressure bleed between each cycle. Then, the disks were slowly pressurized until failure. The first sample ruptured at 10,720 psi and the second failed at 10,730 psi. Both values are within the 2% tolerance range for the disk rating. 8 Two
Fike PAD-I disks were tested to determine the impact of collapse pressure cycles on the disk rupture pressure. One
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Figure 15.10. Schematic to Illustrate Inward-acting Rupture Disks
15.2.4.2.4
Testing for Downhole Application - Inward-acting Rupture Disks Rupture disks can be
designed to relieve pressure in either direction. A “collapse” disk may be desirable if the inner string collapse resistance is significantly lower than the outer string MIYP. Figure 15.10 illustrates a potential installation of an inward-acting rupture disk. The disk is installed in the 16 in. casing string and is designed to fail inward. If high pressures builds in the C annulus but not in the B annulus, the resulting differential pressure may threaten to collapse the 16 in. casing. Rather than risk a mechanical failure, the rupture disk allows the pressure to equalize between the two annuli. Fike designs “collapse” disks that have rupture pressures specified at the collapse resistance of a casing and a specified minimum back pressure that exceeds the casing minimum internal yield pressure. Disks with a 3,590 psi ±5% rupture rating at 72◦ and a minimum back pressure rating of 8,000 psi were tested under cyclical loads. Three disks were cycled 10 times to 8,000 psi in the “burst” direction and then ruptured in the “collapse” direction, all failing within specification [16]. disk was cycled to 60% of disk rating in the reverse direction, then cycled to failure in the normal direction. The disk failed at 3,624 psi, or within the specified range of 3,434 psi to 3,636 psi at ambient temperature. The second disk was cycled to 71% of the disk rating in the reverse direction, then cycled to failure in the normal direction. This second disk failed at 3,686 psi, or 50 psi outside the design limits. The test indicated that cycling between collapse and burst causes some work hardening of the disk material but has minimal impact on performance. A similar test was conducted using OSECO disks with nominal pressure ratings of 4,776 psi. The disks were pressurized to approximately 3,000 psi in the reverse direction (63% of rating). Normal pressure was then slowly applied while holding 3,000 psi backup pressure until the disks failed. The three differential failure pressures were 4,758 psi, 4,778 psi and 4,700 psi, all within 2% of specification.
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Table 15.5. Summary of OSECO Rupture Disk Test Data Rating
Burst Pressure
Backup
% of Rating
5,100 psi
5,150 psi
0 psi
101%
5,134 psi
0 psi
101%
4,484 psi @ 199◦ F
0 psi
99%
4,420 psi @ 206◦ F
0 psi
97%
4,476 psi @ 195◦ F
0 psi
98%
4,470 psi @ 197◦ F
0 psi
98%
7,220 psi @ 206◦ F
0 psi
99%
7,230 psi @ 197◦ F
0 psi
99%
7,780 psi
3,022 psi
100%
Backup pressure held constant in first
7,820 psi
3,042 psi
100%
three tests while burst pressure increased
7,724 psi
3,024 psi
98%
until failure
0 psi
5,810 psi
122%a
2,168 psi
0 psi
120%
Protective cap interference
2,230 psi
0 psi
124%
Protective cap interference
1,792 psi
0 psi
100%
No cap installed
1,820 psi
0 psi
101%
Redesigned (shortened) cap
3,788 psi
0 psi
108%
Protective cap interference
3,476 psi
0 psi
99%
No cap installed Pressure in first three tests
4,537 psi
7,379 psi
4,776 psi
1800 psi
3,500 psi
Comments Test conducted in 20 in. coupling
Ratings at 200◦ F; test temperatures noted
8,397 psi
8,388 psi
0 psi
100%
(burst)
0 psi
4,222 psi
115%
was cycled to 70%/80%/90% of
0 psi
4,010 psi
109%
rating before rupture
0 psi
3,524 psi
96%
Pressure
3,667 psi
in
last
two
tests
was
cycled
to
70%/80%/90% in opposite (collapse)
7,458 psi
7,458 psi
89%
direction before rupture in indicated direction
a The % of Rating for reverse pressure (collapse) tests is compared to the burst rating; a collapse rating is not specified.
15.2.4.2.5
Summary of Testing for Downhole Application The test history described above is included
in Tables 15.5 and 15.6 for reference. Additional test data available at the time of publication is also summarized. Not all of these disks have bi-directional ratings. For disks without a back-pressure rating, whenever the disk is failed in the reverse (collapse) direction, the value in the “% of Rating” column is in comparison with the disks nominal rupture rating in the normal direction. It is shown in italics for reference and is not used to determine the acceptability of the test results. 15.2.4.2.6
Test of Cemented Disks Tables 15.5 and 15.6 include tests with either fluid or atmospheric
backup. Downhole, the disk may have hardened cement behind it. A test program with Halliburton was designed to determine if the disk still functions as designed when placed in a cemented casing string. An OSECO rupture disk was placed in the BOSS collar of 20 in. casing. The casing was concentrically centered inside a 27 in. thin wall pipe and cemented with 20% quality foam cement. The inside of the 20 in. casing was pressurized until the disk ruptured at 4,667 psi, 2.3% below its nominal rating, but within the specified 5% tolerance band. Upon removal of the outer 27 in. pipe, the cement was vertically cracked outside the rupture disk, allowing the pressure to escape. This test indicated cement does not adversely impact rupture disk performance. EPT Drilling
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Table 15.6. Summary of Fike Rupture Disk Test Data Rating
Burst Pressure
Backup
% of Rating
10,000 psi
10,330 psi
0 psi
100%
Test at 150◦ F; rating = 10,317 psi @ 150◦ F
10,370 psi
0 psi
101%
Test at 150◦ F; rating = 10,317 psi @ 150◦ F
0 psi
10,330 psi
100%a
0 psi
10,360 psi
100%a
Test at ambient
13,910 psi
3,000 psi
104%
Test at ambient
13,750 psi
3,000 psi
103%
Test at ambient
10,720 psi
0 psi
102%
Ambient; cycle pressure 50%/70%/80%/90%
10,730 psi
0 psi
102%
Ambient; cycle pressure 50%/70%/80%/90%
3,500 psi
Comments
Test at ambient; rating = 10,476 psi
3,492 psi
0 psi
99%
0 psi
4,762 psi
135%a
Burst cycle to 3,000 psi before collapse
4,500 psi
0 psi
4,626 psi
102%a
Burst cycle to 4,000 psi before collapse
3,500 psi
3,624 psi
0 psi
103%
Collapse cycle to 2,106 psi before burst
3,686 psi
0 psi
104%
Collapse cycle to 2,500 psi before burst
0 psi
3,590 psi
100%
10 burst cycles to 8,000 psi before collapse
0 psi
3,604 psi
100%
10 burst cycles to 8,000 psi before collapse
0 psi
3,670 psi
102%
10 burst cycles to 8,000 psi before collapse
0 psi
3,875 psi
108%
110 burst cycles to 8,000 psi while holding
0 psi
3,740 psi
104%
3,069 psi reverse (collapse pressure), then collapse to
0 psi
3,800 psi
106%
10 burst cycles to 8,000 psi before collapse
9,168 psi
0 psi
102%
25 burst cycles to 7,650 psi while holding
8,895 psi
0 psi
99%
5,950 psi back-pressure, then fail in burst
9,105 psi
0 psi
102%
direction
8,755 psi
0 psi
98%
25 burst cycles to 7,650 psi with 0 psi
9,080 psi
0 psi
101%
back-pressure, one reverse pressure cycle
9,095 psi
0 psi
102%
to 5,950 psi, then fail in burst direction
3,590 psi
3,590 psi
failure
8,947 psi
8,947 psi
a The % of Rating for reverse pressure (collapse) tests is compared to the burst rating; a collapse rating is not specified.
15.2.4.2.7 Available Rupture Disks Rupture disks designed for casing applications can be obtained from Fike Corporation, 704 South 10th Street, Blue Springs, Missouri 64015, Phone (816) 229-3405 www.fike.com. In addition, Hunting International, a major supplier of rupture disks to BP, can be reached at Hunting International, 2 Northpoint, Suite 500, Houston, Texas 77060 Phone (281) 442-7382. 15.2.4.2.8
Rupture Disk Selection and Specification
15.2.4.2.8.1 Pressure and Temperature Selection Select rupture disks so that the lower pressure rating of the disk exceeds the pipe MIYP at operating temperatures. Selecting an outward-acting rupture disk in this manner ensures that disk performance is above the API internal yield pressure upon which a deterministic design for internal pressure differential will be based. Further, since the increment in internal pressure differential between internal yield and actual rupture is quite large, the disk should still rupture before the tube body. For example, if the disk is installed in 20 in. 129.0 (0.625 in. wall) X-56 casing, then the disks lower pressure rating bound should be above the casings 3,060 psi MIYP. A disk with a rupture pressure EPT Drilling
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reliability of 2% should have a nominal rating of at least 3,122 psi at operating temperatures (MIYP / 0.98), 3,221 psi if the reliability bands are 5% (MIYP / 0.95). For Gulf of Mexico applications, the disks installed in Huntings subs will have a ±5% pressure tolerance. The appropriate operating temperature does not require an exact specification. Higher temperatures tend to degrade the rupture pressure rating of the disk; conversely, lower temperatures increase the rating. This trend aligns with the intended purpose of the plug, which holds pressure during cooler drilling operations, but fails under producing (hot) conditions. Thus, the specified operating temperature needs to be above the highest temperature encountered during drilling operations (providing an extra margin of safety during drilling operations), but below the temperature expected while the well is producing (premature rupture of a disk at this point is of no consequence). For surface strings in offshore wells, this temperature is commonly between 125◦ F to 150◦ F. For the example 20 in. 129.0 X-56 casing, a Fike PAD-I rupture disk with a nominal 3,500 psi rating at 100◦ F is an acceptable candidate, with a rating of 3,447 psi at 150◦F and a 5% lower limit rating of 3,274 psi. Rupture disk ratings appearing in increments of 500 psi is a common practice with suppliers. Rupture disks that protect the casing from collapse loads are specified based on the subject casing only. The rupture disk rating should be less than the casing collapse resistance but above any design collapse loads9 . The disk minimum back-pressure should exceed the casing MIYP. Additional principles to follow in the design of rupture disks include the following: • Whenever possible, and only with appropriate review of exceptions, the integrity of the deterministic API ratings should always be maintained. For example, if the collapse rating of the inner boundary of an annulus is lower than the internal yield rating of the outer annulus boundary, it is more appropriate to consider the installation of an inward-acting rupture disk on the inner string rather than intentionally weaken the outer string by installing an outward-acting rupture disk rated below the collapse resistance of the inner string. • When designing rupture disks for tubulars which (a) form the outer boundary of an annulus and (b) are in contact with formation, the appropriate external pressure for disk design is the fracture pressure of the formation, not the pore pressure. This assumption allows one to investigate the worst case when (a) the rupture pressure of the tubular itself is much higher than the internal yield pressure and (b) rupture of the disk membrane is delayed by high back-up pressure, thus generating maximum pressure in the annulus. By this means, appropriately conservative consideration of possible collapse of the inner boundary of the annulus can be addressed. • Rupture disks should not be installed on production tubing or production casing, liners or tiebacks. Table 15.7 shows the temperature derating curve for Fikes standard disks. The rating at one temperature can be converted to an equivalent rating at another temperature by using these ratios. 15.2.4.2.8.2
Seals If space allows, an O-ring is installed to provide a seal between the rupture disk and
the pipe or collar. O-ring material needs to be compatible with mud chemistry; for synthetic oil-based muds, 9 Inasmuch
as design loads are often allowed to approach BP’s collapse design factor of 1.0, this window may be difficult to
achieve.
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Table 15.7. Fike Temperature Deration Temperature, ◦ F
% of Rating at 72◦ F
72
100
100
99.0
150
97.5
200
95.0
250
94.5
300
94.0
350
93.0
Figure 15.11. Hunting O-Ring Seal Configuration for Outward-acting Rupture Disks
this leads to the selection of Viton. Nitrile or Buna-N is commonly used with water-based muds. For more information on elastomer selection, see the BP elastomers website at http://ut.bpweb.bp.com/elastomers/. The disks also come in housings with NPT threads. Teflon tape or thread lock compound is applied to the threads to fill voids between the mating surfaces and provide a seal. Rupture disks used in the Gulf of Mexico are coordinated through Hunting, the US patent holder on the use of disks to relieve APB (see [16] for details). The disks should be installed with a thread lock compound to ensure that downhole vibration does not back out the disk and relieve O-ring seal compression. Both Fike and Hunting recommend using Lock Tite 272, in part because the disks can be later removed by heating the compound to 500◦F. This flexibility allows field returns to be reworked by removing the old disks, inspecting and repairing the subs, and then installing and testing new disks. The old disk should be discarded, as the removal process will likely affect EPT Drilling
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its performance. 15.2.4.2.8.3 Field Application Multiple rupture disks are run in the string to provide redundancy and to cover the variety of fluid densities and pressures that result in peak differential pressures over the length of the string. Typical installations include two to five sets of two disks, run in APB subs, located 180◦ apart. At a minimum, outward-acting rupture disks should be run in two locations, one sub above the previous shoe and a second sub below the previous shoe. This ensures that the two annuli are connected through the upper sub while providing a leak path to the formation via the lower sub. For long strings, additional subs are recommended, spaced over the length of the string. The top rupture disks are placed at least 200 ft (60 m) below the mudline. This prevents the disks from interfering with abandonment procedures by allowing adequate intervals for setting cement plugs or other containment measures. The abandonment procedures for a particular well should be consulted to determine if 200 ft (60 m) is sufficient. Once the rupture disk is installed, the open cavity may be filled with grease and a plastic protective cap is fitted into the opening. The cap is intended to prevent cement from filling the cavity, ensuring there is adequate room for the disk to deform and rupture. Tests at Hunting have demonstrated this cap may slightly raise rupture pressure of the disk if it interferes with the disk and provides reinforcement. Care must be taken to ensure there is adequate standoff between the cap and the rupture disk. This requires an acceptance test for any new disk designs, where the rupture pressure of disks with the protective cap is compared with the rupture pressure of an uncovered disk. 15.2.4.2.8.4 Ordering and Quality Assurance Early application of rupture disks resulted in several quality-related failures due to their novelty as a downhole tool. Learnings from these incidents have been incorporated into BP’s current rupture disk acquisition procedure and should be rigorously followed. Contact EPT for further details. 15.2.4.3
Syntactic Foam
Syntactic foam (see Figures 15.12 and 15.13) is similar in composition to the foam used on riser buoyancy modules. It consists of hollow glass spheres in a polymer carrier. Originally strapped to the exterior of casing, today the foam is more often molded onto the outer surface of the casing that forms the inner string of the annulus requiring pressure control. The molding takes place using injection into molds. The pipe is then moved into special ovens for curing. Syntactic foams belong to a class of materials known as reinforced cellular solids [36]. Figure 15.14 shows the typical response of syntactic foam when it is subjected to hydrostatic pressure. Three distinct regions characterize the material property curve: the linear region (region of elastic deformation), the collapse plateau and the final pore collapse region (also known as the region of densification). The linear region ends at what is termed the “crush pressure”, that is, the pressure required to initiate collapse of the interstitial voids in the cellular solid, which typically occurs when the volumetric strain is 2 to 5% (see Section 15.2.4.3.1). The linear region is followed by a long “collapse plateau” characterized by collapse of the interstices. The compressive strains in this region, as expected, are permanent and do not vanish when the pressure external to the foam is removed. The collapse plateau terminates with the beginning of the region of pore collapse, EPT Drilling
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Figure 15.12. Length of 11-3/4 in. Casing With Molded Syntactic Foam Module
Figure 15.13. Composite (Casing/Foam) Length Before Running Downhole
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Figure 15.14. Typical Behavior of Syntactic Foam
or densification, where the foam cellular structure degenerates completely and the material behaves like a continuum. As the pores collapse, the slope of the stress-strain diagram in this region approaches the elastic modulus of the substrate material (resin) of the foam. An important characteristic property is the rate of crushing, or the volumetric strain rate. After crushing begins, a sample of foam requires a finite time to compress by a certain amount. The volumetric strain rate is a function of pressure and temperature. The length of the collapse plateau indicates the foam compression ratio. Depending on foam composition, the magnitude εu can vary between 30 and 60%. However, based on theoretical principles, the maximum value attainable is 67% [85]. Additives and the cellular structure of the foam influence the compression ratio. Two types of additives include glass microspheres (also known as microballoons) and carbon fiber macrospheres. The diameter of glass microspheres varies between 1 micron (10−6 m) and 100 microns (10−4 m), while macrospheres can have diameters approaching several eighths of an inch. The onset of crushing in the material is controlled by a proper selection of D/t ratios of the spheres and the bulk modulus of the parent resin [85, 11]. In the offshore drilling industry, the primary function of syntactic foam is to provide buoyancy for risers in deepwater application. Syntactic foams ensure [40]: • High bulk modulus; • Low coefficient of thermal expansion; • Low water absorption. EPT Drilling
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In these applications, foams are typically unusable if the crush pressure is exceeded (see Section 15.2.4.3.1). Syntactic foams have also been used as insulation materials for subsea pipelines. The primary goal of the designer is to ensure the foam module can withstand the operating temperature and pressure without exceeding the crush point (i.e., operate in the linear region–see Figure 15.14). However, when applied for APB mitigation, crushing of foam at a pre-determined temperature and pressure is desired. To achieve this, one must ensure the syntactic foam has the following properties: • A high bulk modulus below a critical pressure; • A high compression ratio when the critical pressure is exceeded; • Resilience above the critical pressure for cyclic load applications. Syntactic foams used in offshore riser applications are classified as “rigid” foams, characterized by a matrix of low compressibility thermoplastic resin and a porous, but impermeable, closed cell structure. When the pressure exceeds the crush pressure (see Section 15.2.4.3.1), the foam module compresses rapidly due to the following: • Collapse of the embedded glass microspheres; • Invasion/absorption of fluid into the pore spaces10 . Foams can also be constructed with elastomeric materials. These are typically “soft” flexible foams with low bulk moduli. It is probable that soft foam modules made of elastomers with low bulk moduli (rather than high modulus rigid thermoplastics) and reinforced with hollow glass microspheres can provide the desired combination of strength and post-crush resilience for APB mitigation. The microspheres can be made with a suitable material (glass, carbon, saran, etc.). Determination of the required quantity of microspheres is based on their size and density, such that rapid compression is initiated at a target pressure. After collapse of all microspheres, the matrix would have the properties of a flexible un-reinforced cellular solid if the transition glass temperature (point at which a polymer becomes very flexible) of the elastomer is correct. The support provided by the filler (microspheres) will ensure the strength required to withstand installation and pre-production pressures on the foam module. Elastomers can undergo significant deformations (up to 500%), but on unloading, the material returns to its original shape [36]. Typically, the moduli of elastomers are less than those for thermoplastics by a factor of 1,000 or more. However, the state of the technology is such that these reinforced elastomeric foams cannot be engineered to meet the design requirements for installation in a typical deepwater subsea annulus [36]. 15.2.4.3.1 Crush Pressure The material property curve shown in Figure 15.14 is a function of temperature. In particular, the crush pressure, pcr , is strongly influenced by temperature. The crush pressure of the reinforced foam is a function of the yield strength of the parent resin, the properties of the reinforcing fillers in the pore spaces and the geometry and distribution of the voids [69]. 10 It
has been suggested that the absorption of water by syntactic foams is more a process of diffusion (as described by Fick’s law for porous media) into the pores due to cracks at the surface of the microsphere and the binder (thermoplastic resin), rather than bulk compression, causing a collapse of pore space [21]. This theory may explain the irreversibility of volume change after crushing begins.
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In fact, Gibson and Ashby derive the elastic moduli and yield strengths of a variety of both reinforced and un-reinforced cellular solids [36]. The structural strength of syntactic foam is a result of reinforcing hollow spherical fillers (microspheres or macrospheres) with the surrounding resin matrix. Though a sphere has the greatest resistance to hydrostatic loading, un-reinforced hollow spheres collapse at pressures lower than those predicted by theory, since they have geometric flaws that cause failure by elastic buckling. Reinforcement provided by the resin surrounding syntactic foam prevents the sphere from buckling and forces it to fail at a stress state very near pure hydrostatic compression. This effect, thus, multiplies the collapse strength of the sphere by a factor that depends on the modulus (stiffness) of the parent resin and the relative size of the spheres. Glass microspheres, which are both very small (100 to 200 microns) and very stiff (300,000 to 500,000 psi), are reinforced by a factor as high as six. Carbon fiber macrospheres, which are larger (0.375-in.) and “softer” (30,000 to 50,000 psi), have smaller magnification factors between 1 and 2.8. This implies that the crush pressure of syntactic foam is controlled by two variables-the bulk modulus of the parent resin and the collapse strength (in the von Mises sense) of the reinforcing spheres. A defining property of a thermoplastic resin is its “glass transition temperature.” The glass transition temperature is analogous to the melting point of a metal. Just as a metal loses structural integrity as its temperature reaches the melting point (i.e., begins to creep/flow), a thermoplastic resin loses its structural strength and cannot support a load when the operating temperature approaches the glass transition temperature. In other words, the yield strength and the bulk modulus of the parent resin are functions of the operating temperature. At temperatures that approach the glass transition temperature, the yield strength and modulus of the parent resin decrease rapidly. The crush pressure of the amalgam (i.e., resin and reinforcing filler material/foam module) becomes a function of temperature, since degradation of structural strength can occur due to failure of either the parent resin or the filler material. Figure 15.15 illustrates the effect of temperature on crush pressure for three different sample syntactic foam grades in use in the Gulf of Mexico. Of the two kinds of fillers (reinforcing material) used in syntactic foam-glass microspheres and carbon fiber macrospheres–the latter cannot be used at high temperatures, since carbon macrospheres have minimal resistance to temperatures above 212◦ F. Foams with glass microspheres, on the other hand, can withstand high pressures at high temperatures. 15.2.4.3.2
Volumetric Strain Rate The volumetric strain rate is the rate of foam compression after
crushing is initiated. If the fluid pressure acting on the foam module is greater than the crush pressure, crushing continues until the foam can crush no further. If the pressure is reduced, crushing does not cease; rather, the rate of crushing reduces drastically. In fact, the behavior of foam is characterized by creep with small volumetric strain rates, owing to the creep-like behavior of the parent resin that composes the foam. Volumetric strain rate curves for syntactic foam exhibit primary, secondary and tertiary regions of creep that are characteristic of viscoelastic materials. 15.2.4.3.3 Design, Performance and Selection of Syntactic Foam Modules Design specifications for foam modules require calculation of the following quantities: • Total volume of foam to be installed; EPT Drilling
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Figure 15.15. Effect of Temperature on Crush Pressure of Syntactic Foam
• Crush pressure, or pressures of foam modules, if more than one grade of syntactic foam is used (grade denotes crush pressure); • Geometry of the module: outside diameter, inside diameter and length per joint. Optimization of these parameters is based on the loads anticipated during the service life of the foam module. The total volume of the module is related to the compression ratio and the anticipated thermal expansion of fluid in the sealed annulus. The crush pressure(s) is determined using the allowable APB in the annulus. In turn, the allowable APB is determined by string design. The casing string on which the modules are installed determines the geometry of the foam module. Furthermore, operational considerations, such as clearances at the rotary table while running the composite casing/foam module strings, influence the size of the foam module. Performance of the foam module is dependent on the design specifications, wellbore thermal response, and the annulus thermal response. 15.2.4.3.3.1 Service Life and Design Basis Since the innermost annuli experience the greatest temperature changes (both during injection and production), foam modules are typically installed on the production casing. The foam modules should be designed to withstand installation pressures (hydrostatic) and EPT Drilling
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temperatures (undisturbed) without crushing. They must also withstand loads produced by subsequent wellbore operations before exposure to the pressures and temperatures caused during production. Typically, these operations include cementing the lower section of the casing on which the foam modules are mounted, the drilling of a smaller (and hotter) hole section and the installation and cementation of a liner or other strings per well design. The final and most severe loads on the foam occur when the well is placed on production. • Cementing the casing to which the syntactic foam is attached is not likely to affect the foam module, unless reduced flow area in the annulus causes a considerable increase of quiescent hydrostatic pressure. This is a calculation that may be performed during the design check process, after selection of foam material and module sizing. • Circulation of drilling mud in the hotter and deeper hole sections raises the temperature of fluids in preceding annuli. The annulus with the foam modules experiences APB due to this temperature rise and must be able to withstand the resulting pressures. • Temperature increase due to installing and cementing subsequent tubular strings is usually less than the increase caused by drilling their corresponding hole sections. During production, APB is the chief design constraint on the foam module. Pressure increase in the annulus is invariably accompanied by temperature increase, which is caused by the expansion of a relatively incompressible liquid in a sealed region. The reverse is not true (i.e., temperature increase need not always be accompanied by a pressure increase). For example, the annulus in question could have an open hole section that allows fluid leak off when APB reaches a certain value. Alternatively, rupture disks (or alternate mitigation strategy) might be placed on the outer string of the annulus. Irrespective of the actual mechanisms, there are instances when the annulus containing the foam module is not sealed and the annulus experiences a temperature increase. In this event, the foam modules should be able to withstand the pressures in the annulus (which are close to hydrostatic pressures). This is an important consideration, since the crush pressure of the foam module decreases significantly at the temperatures expected during production. The design should ensure that the modules crush only when the temperature and pressure are in the prescribed range. 15.2.4.3.3.2
Size and Volume Calculations The installed volume of foam is based on the expansion
volume of the annular fluid and the compression ratio of the foam. Ideally, the volume of the module is chosen such that its total compression equals the net volume change of the annulus (i.e., volume expansion of fluid due to temperature change, minus the volume change of the annulus due to casing expansion/contraction). The total volume of foam required and the geometrical constraints of the annulus can be used to calculate the D, d, and length of foam per joint. A safety factor of 1.1 on the AFE calculations is used to account for the uncertainty (typically 5 to 7%) inherent in heat transfer calculations. Higher safety factors are advisable to account for differences between design conditions and field conditions or variations in foam performance. 15.2.4.3.3.3
Determination of Crush Pressure and Temperature For the reasons explained in Section
2.1, foam modules are designed so that the crush pressure is: • Greater than installation hydrostatic pressures at installation temperatures; EPT Drilling
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Figure 15.16. Determination of Onset of Crushing in Syntactic Foam Modules
• Greater than hydrostatic pressure, plus the APB caused while drilling deeper hole sections; • Greater than hydrostatic pressure at production temperatures to ensure crushing occurs only when the annulus is sealed. Figure 15.16 illustrates the process for determining the onset of crushing in foam modules. Let curves AA’ and BB’ represent temperature and pressure in the annulus as a function of time. Point A represents the initial undisturbed temperature and point B represents the hydrostatic pressure at the top of the given foam section. The line DD’ represents the maximum hydrostatic pressure on the module (i.e., the hydrostatic pressure at the bottom of the given section of foam). The curve CC’ represents the crush pressure of the foam module as the temperature rises in the annulus. The curve CC’ is obtained from the material behavior of the foam (i.e., crush pressure vs. temperature behavior - see Figure 15.15). Curves AA’ and BB’ are obtained by determining annular thermal/pressure response. The point X determines the point of crush initiation when temperature and pressure increase together in the annulus. A functional design is possible when a point of intersection between BB’ and CC’ can be found. The magnitude of pressure, represented by XX’, should be less than the allowable APB, which EPT Drilling
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is determined based on casing design. The problem in Figure 15.16 reduces to the following: Given, 1) the temperature and pressure vs. time curves AA’ and BB’, respectively, for a given section of the annulus, and 2) lines DD’ and the point C’, the goal is to design foam with a curve CC’ that always intersects BB’. This procedure ensures the foam modules do not crush if temperature alone increases in the annulus. In an unsealed annulus, the pressure change is represented by the horizontal line DD’, indicating that it remains constant. The behavior of curve CC’ ensures that the foam can sustain hydrostatic pressures when temperature rises in the annulus. 15.2.4.3.4
Operational Issues
Performance properties required module volumes of syntactic foams are
determined as described in Section 15.2.4.3.3. The required module volumes are then determined. Prototype samples that meet the required design goals (i.e., samples that exhibit the desired variation of crush pressure with temperature) are fabricated in the laboratory through a process of trial and error. The syntactic foam modules are then cast on the outer diameter of the inner casing of the annulus requiring APB mitigation. The manufacturing process consists of two steps. First, based on the chemistry of the prototype sample, appropriate amounts of the molten polymeric resin and glass microspheres are prepared and mixed. The ratio of the volumes of microspheres and resin reflects the expected compression ratio of the foam. The second step consists of placing a hollow steel cylindrical mold on a given joint of casing. The cylindrical mold is placed concentrically on a given joint of the casing, so that the outside diameter of the and the inside diameter of the mold form an annular space. The geometry and volume of the annular space are such that the requirements specified in Section 15.2.4.3.3.2 are satisfied. The mixture of molten resin and glass microspheres is injected into the annular space between the casing and the mold. The assembly is then cured in a furnace at a constant temperature until the mixture solidifies. After completion of the curing process, which typically takes one day, the mold is removed. When the mold is removed, the solidified syntactic foam remains attached (integrally bonded) to the outside surface of the casing. During casting of the modules onto the casing, test samples of the molten mixture are sampled for quality control testing. After the foam modules are installed on the joints, test samples are tested in a laboratory to ensure that the foam modules exhibit the desired performance properties. 15.2.4.3.5 Transportation, Running and Installation The foam modules are installed only on the body of the casing joints. The regions close to the pin and box ends are exposed. Furthermore, rig-handling procedures require the foam module to be at a specified distrance from the pin and box ends. Due to the asymmetric placement of the molded foam on the casing, the composite casing length center of gravity does not correspond to the geometric center of the length. As a result, special handling systems and procedures are required transporting the lengths to the rig. Figures 15.17 and 15.18 illustrate a composite length in a bolster designed specifically to avoid damage during transport.
15.3
Subsea Tieback Design
A complete subsea tieback design requires input from platform designers. The current section is intended to provide a drilling engineer with design basics, specifically: EPT Drilling
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Figure 15.17. Composite Length of Casing and Syntactic Foam in Bolster
Figure 15.18. Four Lengths of Casing and Syntactic Foam in Bolster
• Furnish an overview of tieback design and the features which, as a minimum, tieback designs for BP should consider; • Provide a drilling engineer with sufficient understanding of the issues involved in tieback design; • Provide a drilling engineer with simple calculation methods useful for front-end engineering studies and preliminary designs; • Provide a common starting point for drilling and specialist structural engineers to jointly develop the EPT Drilling
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optimum tieback design for a specific project. The discussion focuses on tiebacks from a fixed platform to a subsea wellhead or mudline suspension system. It does not address design issues for tension leg platform tiebacks nor tiebacks to jackups with lengthy tensioned conductors. The calculation procedures given below are not adequate by themselves to ensure a satisfactory design. However they will permit the development of a sensible initial design. Advice on structural design can be obtained from EPT. In particular the interaction of casings in compression with platform motions and local environmental forces is an area where the drilling engineer must seek assistance.
15.3.1
Design Issues Overview - Description of a Tieback
It is usually economically desirable to minimize the time between facilities installation and full field production. To this aim, subsea wells can be drilled using a template above which the production platform is later installed. These subsea wellheads can then be tied back to platform wellheads and completed. The tieback enables the casings to be run back to the platform and the well to be controlled with a surface wellhead and Christmas Tree. A typical tieback configuration as used by BP consists of three strings, a 20 in. conductor and 13-3/8 in. and 9-5/8 in. casings as shown in Figure 15.19. The 20 in. conductor is freestanding, supported at the seabed by the subsea wellhead and laterally at intervals by platform conductor bracing guides. The 13-3/8 in. casing supports the surface wellhead, while the 9-5/8 in. is the production casing string.
15.3.2
Problems to be Resolved during Design
The design of the tieback must consider all the anticipated combinations of temperature, pressure and environmental loadings, both in the final, as-installed condition and at the various stages during the installation. As with conventional production wells the tieback production casing string will have to contain wellhead pressure in the event that the production tubing fails. In addition to the customary casing design requirements of burst, tension and collapse, the tieback design process has to resolve the following issues: • Thermal Growth. In a production well the average temperature of tubing and casing will be higher while producing than when installed or shut-in. Thermal expansion of tubing and casing will result in the surface wellhead moving upwards. Conversely water injection wells generally can exhibit downward movement owing to temperature decrease. The extent of wellhead motion caused by thermal and pressure effects is essential information for the topside pipe work. • Load on Equipment. Thermal and pressure effects can cause large forces on wellhead equipment, and large changes from the initial installation loads. For example, in a production well, an uncemented length of 9-5/8 in. casing below the subsea wellhead will normally be in tension. However, a sufficient temperature increase will change the casing load to compression. This can result in both increased stresses in the 9-5/8 in. below the seabed wellhead due to helical buckling and in upward motion of the 9-5/8 in. at the seabed wellhead unless a positive mechanical lockdown mechanism is present. Whether such motion can be permitted to occur, and whether the stresses due to buckling (if present) are acceptable have to be resolved. EPT Drilling
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Platform Wellhead
Sea Level
20in Tieback 133/8in Tieback 95/8in Tieback
Seabed Wellhead
Seabed 26in Conductor 133/8in Casing 95/8in Casing
BPAD003_150.ai
Figure 15.19. Tieback Configuration
• Pre-tension. BP’s tiebacks have required pre-tensioning the 9-5/8 in. casing. Pre-tensioning ensures (a) the 9-5/8 in. does not buckle within the 13-3/8 in. and (b) there is no tendency for the direction of load in the 9-5/8 in. casing at the surface wellhead to change, and hence no possibility of motion at sealing surfaces. Pre-tension does not reduce thermal growth. The extent of wellhead motion is substantially unaffected by pre-tension. It does, however, change the position from which the motion starts. EPT Drilling
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– Pre-tension is not a necessity. Buckling of the 9-5/8 in. may not result in excessive bending stresses, nor prevent the passage of tools. Service conditions may not cause load reversal in the 9-5/8 in. at the surface, or wellhead assembly detailing may make concern over load reversal at seals irrelevant. – Reducing or eliminating pre-tension can also reduce centralization and material strength requirements for the 13-3/8 in. and thus cost. The need for and degree of pre-tension has to be resolved based on service conditions and equipment limitations. • Compression in the 13-3/8 in. The 13-3/8 in. casing as shown in Figure 15.19 usually supports much of the tubing weight, the 9-5/8 in. and its pre-tension and the weight of topside equipment; it is thus normally in compression once the installation is complete. The 13-3/8 in. will tend to buckle. – Buckling of the 13-3/8 in. is a more complex problem than the simple pin ended column. The extent to which it can buckle is limited externally by the 20 in. conductor. The internal strings while in tension will also exert a stabilizing influence on the 13-3/8 in. once they contact the 13-3/8 in. internal wall. Usually buckling of the 13-3/8 in. will result in unacceptable bending stresses exceeding yield even within the constraints resulting from the 20 in. and inner strings. – The 13-3/8 in. is prevented from buckling as a helix by using rigid centralizers which provide lateral support from the 20 in. typically one or two centralizers per length (10 m) are used. Lateral support from the 20 in. implies that platform displacements imposed on the 20 in. at horizontal guide frames, and local deflections of the 20 in. due to environmental loadings on it both affect the 13-3/8 in. A thorough evaluation of these effects requires specialist structural engineering assistance. The need for, spacing and constructional detail of the centralizers and the adequacy of the 13-3/8 in. have to be resolved. • Function of 20 in. The primary role of the 20 in. in BP’s tiebacks is to isolate the 13-3/8 in. from direct environment loads. However, its use as a compression member can be considered. Using the 13-3/8 in. as the main compression member in the tieback is disadvantageous when initial overpull is used to pre-tension the 9-5/8 in. slips. A possible alternative is to use the 20 in. as a compression member, rather than solely as a free standing barrier between the 13-3/8 in. and direct wave loading. The greater vertical stiffness of the 20 in. and 13-3/8 in. acting together means that less overpull is required to achieve the same residual tension in the 9-5/8 in. Where it is necessary to pre-tension the 9-5/8 in. it may be possible to reduce the number of centralizers needed on the 13-3/8 in. by also pre-tensioning the 13-3/8 in. provided the 20 in. has spare compressive load capacity. In general, it is preferable to minimize or eliminate the need for any pre-tensioning. Rigidly connecting the 13-3/8 in. and 9-5/8 in. to the 20 in. at the surface will reduce thermal growth in producing wells. However it will tend to increase the compressive loading in the 9-5/8 in. due to temperature rise. Again the effects of simultaneous lateral environmental loadings and axial compression require specialist engineering assistance to resolve. EPT Drilling
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15.3.3
The Drilling/Structural Engineering Interface
Review of previous tieback work within BP and its contractors has shown that the physical configuration of the components used and how they work must be fully discussed with those performing the structural engineering. Terms such as “fixed”, “free” and “pinned” can have different meanings to the two disciplines. It is essential that the drilling engineer takes the time to adequately describe component behavior to the structural engineer. This must be done for each stage of the installation process, not just the final configuration, without introducing implied assumptions about the magnitudes and directions of forces, or the capabilities of components. The drilling engineer should work through the following sequence before starting discussions with a structural engineer, since the structural engineer will need at least this information for an adequate analysis: 1. Identify points of ideally no motion - e.g., cement tops. 2. Identify interfaces which provide restrictions to relative motion of casings, and tubing, e.g., locking mechanisms in wellhead systems, and completion details. 3. Clarify how these interfaces should behave for both directions of relative motion, e.g., extent of free travel, manufacturer’s stated load capability, and acceptability of load reversal at sealing surfaces. 4. Clearly identify possible load paths in stacked components. 5. Establish an outline installation sequence and ensure that it leads to both a full definition of the final configuration and the loads which the components experience at each stage of installation. For example, there can be considerable difference in structural behavior between a case where tubing has been set down with say 30 kips at the completion and cannot move down further, but could move up, and a case where the tubing is centered in a PBR and can move either way. The differences on application of thermal and pressure loads can be large even though the as-installed loadings in the outer casings may have little difference in the two cases. 6. Be able to explain the containment mechanism for the various pressure tests, e.g., testing against packers in the casing or against test plugs at the wellhead. 7. Establish the expected service life loads defined in Section 15.3.5. The structural engineer should recognize that the tieback system is not a fully welded or bolted assembly, but incorporates components where structural behavior can depend both on the direction of the load and on what stage the installation has reached. It is important that the boundary conditions of any structural models are fully discussed with the drilling engineer. The structural engineer must clearly establish which boundary features are independent of loadings, and which may change. Also at an early stage the key points where forces are to be calculated to establish component suitability should be agreed with the drilling engineer.
15.3.4
Operational Aspects
Operational issues have to be considered on a project by project basis. However, the following observations are of general applicability: EPT Drilling
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• Sizing. Use standard casing sizes and grades where possible, identical casing lengths ease installation. Possible future access and associated well control requirements should be considered in sizing. • Platform wellhead. Make the tieback wellhead design as similar as possible to the platform wellhead design to maximize component interchangeability and simplify later maintenance. • The most efficient design may well depend on circumstances. For example, on the Gyda platform, running the wellhead threaded on the top length of 13-3/8 in. eliminated casing cutting and slips, but required an exact length 13-3/8 in. pup joint to be prepared, using accurate measurement of distance to subsea wellheads. This measurement is best done when running the 20 in. Conversely, on the Miller platform the slip lock wellheads were installed as a batch after 13-3/8 in. casing installation without using the rig. Slip design should include adequate tolerance between the outside diameter of the casing and the minimum inside diameter capability of the slips. It is highly recommended that a landing joint is isolated and calipered to match slip tolerances. Where vendors of subsea and surface equipment differ, the interfaces between their equipment should be fully reviewed. It is important that component design and operational procedures recognize the large casing stretch which can occur if pre-tension is applied. • Procurement. Casing ovality11 criterion must allow passage of tieback tools. The outside diameter of special drift casing must be checked for required tolerance and internal drifts should be examined to ensure correct sizing. • Centralizers. Hinged rigid centralizers should speed installation. Centralizers at the bottom of the 9-5/8 in. ease alignment. Connections are discussed in Chapter 17. • Alignment. The tieback design should be considered in conjunction with the platform installation and construction tolerances and the verticality of the seabed wellhead/mudline suspension.
15.3.5
Loadings on Tiebacks
15.3.5.1
Environmental
The following loadings should be considered, as static extremes and where appropriate as sources of cumulative fatigue damage: 1. Direct wave forces and wind loads on the conductor; 2. Possibility of undesirable vibrations caused by vortex shedding; 3. The limiting environmental conditions for conductor installation. 11 API/ISO
does not publish an explicit requirement on ovality. Rather, ovality is implied from the tolerances on casing diameter [10]. For sizes less than 4-1/2, the tolerance on outside diameter is ±0.79 mm (±0.031 in.); for sizes greater than 4-1/2, the tolerance on outside diameter is +1.0%D, -0.5%D.
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15.3.5.2
Service Life
These are the loadings associated with various operating conditions. Their relevance to specific well conditions and expected operations should be considered before applying to all designs. 15.3.5.2.1
Water Injection Wells
• Normal Operation – As-installed. Weight and buoyancy and pre-tension (if any) loads only, no thermal or pressure effects. An outline installation sequence should be considered to develop forces at the top and bottom of each string up to and including the completion tubing and topside wellhead weight. – Start Up. As-installed loads, plus injection pressure at surface in tubing. This assumes initial temperature distribution is as at installation. – Injection. As-installed plus injection pressure at surface plus the temperature changes resulting from steady state injection. – Shut Down. As-installed plus temperature changes resulting from steady state injection. – Work-over. As-installed plus additional equipment weight. Loads associated with work-over activities. • Abnormal Operation – Start Up. As for normal operation start up, but with the injection pressure applied to both tubing and casing/tubing annulus. – Injection. Both of (a) as for normal operation injection but with the injection pressure applied to both tubing and casing/tubing annulus, and (b) As (a) but without tubing weight. – Shut Down. As-installed plus temperature changes resulting from steady state injection, without tubing weight. • As a Converted Producer. If development plans include the possibility of conversion from injection to production the resulting temperature and pressure regimes should be considered as for producing wells. 15.3.5.2.2
Production Wells
• Normal Operation – As-installed. As for water injection wells. – Start Up. As-installed, plus shut-in wellhead pressure on tubing. – Producing. As-installed, plus expected flowing wellhead pressure on tubing and temperature distribution for initial steady state production rate. – Shut Down. As-installed plus shut-in wellhead pressure on tubing, plus temperature distribution for initial steady state production rate. EPT Drilling
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– Other. Possible gas lift, cuttings injection or aquifer production operations should be considered. • Abnormal Operation. The relevance of these conditions should be reviewed in the light of the asset annulus monitoring policy. – Start Up. Both of (a) as-installed plus shut-in wellhead pressure on both tubing and casing/tubing annulus, and (b) as (a), but without tubing weight. – Producing. Both of(a) as-installed plus flowing wellhead pressure in both tubing and casing/tubing annulus plus temperature distribution from steady state production through tubing, and (b) as (a), but without tubing weight. – Shut Down. Both of (a) as-installed plus shut-in wellhead pressure in both tubing and casing/tubing annulus plus temperature distribution from steady state production through tubing, and (b) as (a) but without tubing weight. – Work-over. Likely work-over requirements should be considered to develop appropriate loadings. One extreme possibility is as-installed, less tubing, plus BOP and weight of work string in shut-in, gas filled casing. – Well Kill. As-installed with tubing with cold kill weight fluid in 9-5/8 in. and BOP. • Conversion from Production to Water Injection. If it is probable that the production well tieback may be used later for water injection the resulting temperature and pressure regimes should be considered as for water injection wells. 15.3.5.2.3 Fatigue due to Service Life Loads The contribution to fatigue damage of wellhead components and casing connections associated with these service life loads is likely to be small. However it should be assessed using a conservative estimate of operational cycles per year. 15.3.5.2.4
Temperature Distributions The temperature changes for each string should be calculated as
the differences between the set condition, i.e., both ends fixed, and the various service life conditions. The axial and radial temperature distributions have a major effect on forces in the various strings and the best possible estimates of these distributions should be obtained, for example by using the Wellcat software. For the initial design an approximation for the radial temperature distribution is given by
T (r) = [T (r = ro + (T (r = ri − T (r = ro
15.3.6
for casing) − T (r = ri for tubing) ln (ro for casing) ln (ri
for tubing)] ln (r) /ln
ro for casing ri for tubing
(15.36)
for casing) for tubing) /ln
ro
for casing r
.
Installation Sequence
A detailed installation sequence will be required for the final design to ensure the loadings built into the system are adequately considered. The following sequence outlines the major operational steps in a tieback EPT Drilling
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installation for a temporarily suspended well and can be developed to suit specific projects. Such development should comply with asset policies regarding tubing annulus pressure monitoring and communication, together with BP plugging policy for live wells. A complete structural appraisal requires the specific drilling fluid densities, test pressures and equipment weights for each stage. The structural engineer will require a procedure to a similar level of detail to perform an adequate analysis. 1. Run 20 in. conductor with external protection from seawater if required. 2. Overpull to test connection. 3. Run 13-3/8 in. tieback casing string. Displace 20 in. conductor with biocide and corrosion inhibitor treated seawater before landing. Overpull tieback string to check fully engaged (say 20 kips). Slack off. 4. Pressure test 13-3/8 in. casing, pressure acts against suspension plugs (top plug) in the 9-5/8 in. casing. This test pressure should be less than the highest pressure (pressure differential across each plug) already applied to any of the mechanical barriers during the suspension phase. 5. Install HP riser drilling spool and 13-5/8 in. BOP. 6. Run test plug in wellhead and pressure test wellhead/BOP, possibly test against top suspension plug12 . 7. Pull 13-3/8 in.9-5/8 in. annulus packoff13 . 8. Run 9-5/8 in. tieback casing string. 9. Pressure test 9-5/8 in. casing string, pressure applied against top suspension plug, limitations as in step 4. 10. Close annular preventer around the 9-5/8 in. casing and pressure test 9-5/8 in.13-3/8 in. annulus. 11. Following successful inflow and pressure test of 13-3/8 in. to 9-5/8 in. annulus remove BOP and HP riser from top of wellhead. Pull pre-tension (if required) on 9-5/8 in. tieback string. Slack off and measure wellhead downward movement. Cut 9-5/8 in. casing, land and make up BOP and riser. Required pre-tension = residual pre tension + slip/hanger loss + 13-3/8 in. compression. 12. Close pipe ram open 13-3/8 in. to 9-5/8 in. side valve and pressure test 9-5/8 in. surface wellhead pack-off from above. Test pack off from below to same pressure as step 10. 13. Clean-out production casing to top of liner and pressure test. 14. Clean-out liner and conduct drawdown/pressure test. 15. Displace to completion brine. 12 In
UKCS a Certificate of Fitness to Receive Hydrocarbons is required for step 7 onwards.
13 Possibility
EPT Drilling
of pressure trapped below sleeve, this inflow tests the 13-3/8 in.9-5/8 in. annulus.
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16. Run completion (seal assembly, packers, completion accessories as required). Space out. Land tubing hanger. 17. Pressure test tubing hanger from below (production annulus). 18. Pressure test tubing and tubing hanger seals from above. 19. Pressure test DHSV from below by bleeding off pressure above. 20. Plug well in accordance with BP policy. Remove 13-5/8 in. BOP. 21. Install production tree. Pressure test production tree body against tubing hanger check valve. 22. Circulate annulus to packer fluid (if required) and repeat tubing annulus pressure test. 23. Perforate. 24. Produce well.
15.3.7
Initial Design
The installation sequence must be considered during a detailed design since from it are developed the asinstalled loadings in each of the casings and the tubing, i.e., it is the base case which is then changed by the environmental and service life loads. However, to establish an initial design consider the service life loads first, in isolation, to allow rapid development of an initial configuration which will probably prove satisfactory. Once such a configuration has been developed its installation sequence should be considered in detail, with the forces at each stage, e.g., at pressure tests, determined to confirm component suitability and the as-installed forces in each string. The service life and environmental loads can then be considered again but applied to the as-installed condition. The degree of pre-tension, if any, may be determined by working through the service life loads assuming zero pre-tension to find the maximum effective buckling force. The pre-tension is then determined as that value which gives acceptable bending stresses if buckling occurs, and which prevents load reversal at sealing surfaces, if this is required by component design. 15.3.7.1
Thermal Growth
There are several ways to calculate the thermal growth. The simplest procedure, set out below, is applicable to any number of casings which are connected together (for both directions of motion) at the surface wellhead. Further details may be found in most books about structural analysis under the heading “stiffness method”. 1. Calculate stiffness of each string connected to the surface wellhead, including the tubing, Ki = Api Ei /Li .
(15.37)
KT otal = ΣKi .
(15.38)
2. Calculate total stiffness,
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3. Calculate the fixed end actions, FEAT i = Api Ei αT i ∆T i .
(15.39)
The fixed end action for a two element composite string (there may be more than two) may be found from
FEAT i =
αT 1 L1 ∆T 1 + αT 2 L2 ∆T 2 . L2 L1 Ap1 E1 + Ap2 E2
(15.40)
4. Calculate the thermal growth assuming no buckling, δLT =
ΣFEAT i . KT otal
(15.41)
5. Calculate the forces in each string at the wellhead due to the temperature changes, Fai = Ki δLT − FEAT i .
(15.42)
6. If an inner string is in compression the effect of helical buckling (assuming it is not prevented) can be estimated by replacing Ki in (1) and FEAT i in (3) with the alternative expressions for the buckled casing, Ki
(with buckling) =
1 Li Api Ei
+
rci Li , 4Ei Ii
(15.43)
where Ii = The fixed end action for the buckled casing is FEAT i
π Di2 − d2i . 64
(with buckling) = Ki
(with buckling)Li αT i ∆T i .
(15.44)
(15.45)
Equations 15.43 and 15.45 assume the whole length is buckled. If only part of the length is buckled more exact analysis is possible but the difference in results will be small. 15.3.7.1.1
Discussion Normally the effect of helical buckling on the thermal growth will be small in
comparison to the total growth. This is because the axial stiffness of a helically buckled casing is not small, unlike that of an unconstrained buckling column. The contribution of the tubing to the axial stiffness is small, mainly because of its length. However its contribution to thermal forces at the wellhead, even if it buckles, can be large. The inclusion of the tubing assumes that it is not free to slide downwards (for a producing well with a temperature increase) at the completion. EPT Drilling
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Although the effect of buckling on the amount of thermal growth is small, the effect on stress in the buckled casing can be large due to the additional bending stresses in the buckled casing or tubing. If the 9-5/8 in. inner casing is not positively locked down at the subsea wellhead it is possible that expansion of the uncemented section will result in upward motion of the 9-5/8 in. at the seabed wellhead. Similarly the effect of fluid expansion in any sealed annulus below the subsea wellhead requires consideration. 15.3.7.2
Pressure Effects
Pressure changes from the as-installed condition also contribute to wellhead movement and the forces in casing strings. The analysis of Section 15.3.7 is readily extended to include pressure effects. Ballooning forces are treated as fixed end actions, an increase in internal pressure in a string tends to shorten it, to moving the wellhead downwards and so the corresponding fixed end action is negative, while a decrease in internal pressure gives a positive fixed end action. Conversely an increase in external pressure tends to lengthen a string and so the corresponding fixed end action is positive, while for a decrease in external pressure it is negative. For each string the fixed end actions due to ballooning may be calculated, FEABi = 2νi (−∆pi Ai + ∆po Ao )i .
(15.46)
Further discussion of this subject is contained in Chapter 10. It should be noted that the full ballooning force can only be developed for a casing fixed at each end, i.e., zero displacement where Fa = KT otal ∆L − FEABi = 0 − 2ν (−∆pi Ai + ∆po Ao ) = 2ν (∆pi Ai − ∆po Ao ) .
(15.47)
Pressure end area forces are treated as external loads in the analysis (positive upwards) and are added to the sum of fixed end actions due to thermal and ballooning effects to calculate the displacement, ∆L = (ΣFEAT i + ΣFEABi + Σ
Pressure-Area Forces) KT otal .
(15.48)
The forces in individual members are then calculated as before using Fai = Ki ∆L − FEAT i − FEABi . 15.3.7.2.1
(15.49)
Buckling Casings normally have low enough D/t ratios for local buckling not to occur. How-
ever, global buckling should be evaluated. The number of external centralizers required to prevent the 13-3/8 in. from buckling can be estimated by the following procedure derived from the AISC Steel Construction Manual [6], 1. Calculate the transition slenderness ratio between elastic and inelastic buckling,
RT =
s
2π 2 E . fy
(15.50)
2. Choose a trial centralizer spacing L, say 360 in. Calculate L/ρC where ρC is given by EPT Drilling
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ρC =
s
I . Ap
(15.51)
3. Calculate the allowable axial compression,
12π 2 E
Fallow =
, L/ρC > RT 23 (L/ρC )2 [1−(L/ρC )2 ] fy 2R2C , L/ρC < RT . = (L/ρC )3 C 5/3 + 3L/ρ 8RC − 8R3
(15.52)
C
If Fallow is greater than the expected compressive load the centralizer spacing can be increased, while if it is less either the spacing must be reduced or the yield strength or wall thickness increased. For the purposes of initial design the above procedure will demonstrate feasibility. More complex calculations, taking into account that centralized inner strings do not contribute directly to instability of the 13-3/8 in. may result in more economic centralizer spacings [89]. In addition to the ballooning forces, changing pressures result in effective tension or compression tending to either resist or induce buckling. This is addressed in Chapter 12. 15.3.7.2.2 Pre-tensioning As noted in Chapter 12, buckling of casing does not necessarily mean structural failure. The degree of pre-tension needed to avoid buckling in the 9-5/8 in. is the maximum effective compression in the 9-5/8 in. for any of the load cases. Any pre-tension will be additive to the maximum tension in the 9-5/8 in. and for producing wells this may mean that it is difficult not to exceed the maximum allowable tension during well kill if sufficient pre-tension is to be provided to prevent buckling. If the 9-5/8 in. casing is to be pre-tensioned, the required hook load above hanging weight (assuming no lost motion at the slips) can be found from Fhk =
ΣKi Fres . ΣKi − Ktb
(15.53)
where Fres is the desired residual tension. In general, it is preferable to evaluate the impact helical buckling has on casing stress and tool passage and use the least possible pre-tension. Attempting to prevent any buckling can unnecessarily complicate component design through requiring very large pre-tensions.
15.3.8
Guidance on Heat Shrink Sleeve Installation
The area to be covered should be clean, dry and grease free. Minimal thread compound should be applied to the connector before make-up, as the sleeve heating process vaporizes grease and creates gas bubbles under the sleeve. Grease or oil must not be used as a thread lubricant. The area to be covered should be high pressure water or steam cleaned. A solvent cleaner should be used to smooth off any sharp changes in cross section. The connection should then be pre-heated prior to application of the primer. EPT Drilling
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The sleeve is wrapped around the pipe and the zip closed. The sleeve is then shrunk into shape from the center outwards using propane torches. If the sleeve will be in the splash zone, then stainless steel “Band-its” should be installed to increase the mechanical strength of the sleeve over the connector.
15.3.9
Example Calculation
This example works through the stiffness calculations to show how the formulas of Sections 12.4.1 and 12.4.2 are applied. 15.3.9.1
Input Data
A tieback consists of 151 ft of 13-3/8 in. 68 lb/ft casing (∆T = 20 [◦ F] ), with 9,000 ft of 9-5/8 in. 47 lb/ft (∆T = 33 [◦ F] ) inside. The production tubing is 9,000 ft of 4-1/2 in. outside diameter, 4 in. inside diameter tubing (∆T = 32 [◦ F] ). Packer depth is 9,000 ft. The flowing wellhead pressure is 3,000 psi. For all strings, E = 30 × 106 psi and αT = 6.5 × 10−6 [1/◦ F] . 15.3.9.2
Calculation–Structural Stiffness
Ap,13−3/8 =
π 13.3752 − 12.4152 = 19.45 in2 , 4
Ap,9−5/8 =
π 9.6252 − 8.6812 = 13.57 in2 , 4
Ap,4−1/2 =
π 4.52 − 42 = 3.34 in2 , 4
(15.55)
(15.56)
K13−3/8 =
EAp,13−3/8 30 × 106 19.45 = = 3.220 × 105 [lb/in] , L13−3/8 151 × 12
(15.57)
K9−5/8 =
EAp,9−5/8 30 × 106 13.57 = = 2.247 × 105 [lb/in] , L9−5/8 151 × 12
(15.58)
EAp,4−1/2 30 × 106 3.34 = = 927 [lb/in] , L4−1/2 9, 000 × 12
(15.59)
K4−1/2 =
KT otal = K13−5/8 + K9−5/8 + K4−1/2 = 5.476 × 105 [lb/in] . 15.3.9.3
(15.54)
(15.60)
Calculation–Fixed End Action
EPT Drilling
FEAT,13−3/8 = EAp,13−3/8 αT ∆T 13−3/8 = 75, 855 [lbf ] ,
(15.61)
FEAT,9−5/8 = EAp,9−5/8 αT ∆T 9−5/8 = 87, 323 [lbf ] ,
(15.62)
FEAT,4−1/2 = EAp,4−1/2 αT ∆T 4−1/2 = 20, 841 [lbf ] ,
(15.63)
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FEAB,4−1/2 = −2 × 0.3 × 3, 000 × 15.3.9.4
(15.64)
Calculation–Pressure End Force
Fpi ,4−1/2 = 15.3.9.5
π 2 4 = −22, 619 [lbf ] . 4
π 2 4 × 3, 000 = 37, 680 [lbf ] . 4
(15.65)
Calculation–Displacement
δL =
75, 855 + 87, 323 + 20, 841 − 22, 619 + 37, 680 = 0.364 (upwards). KT otal 5.476 × 105
(15.66)
At least 3 significant figures should be retained in , otherwise the next stage can become very inaccurate. 15.3.9.6
Calculation–Casing Forces
F13−3/8 = K13−3/8 ∆L − FEA,13−3/8 = 3.22 × 105 × 0.364 − 75, 855 = 41, 353 [lbf ] ,
(15.67)
F9−5/8 = K9−5/8 ∆L − FEA,9−5/8 = 2.247 × 105 × 0.364 − 87, 323 = −5, 532 [lbf ] ,
(15.68)
F4−1/2 = K4−1/2 ∆L − FEA,4−1/2 = 927 × 0.364 − 20, 841 − (−22, 619) = 2, 106 [lbf ] .
(15.69)
As a check, F13−3/8 + F9−5/8 + F4−1/2 = 37, 900 [lbf ] , the pressure end force.
15.4
Wellhead Loads
For platform or land wells utilizing wellheads that distribute loads directly to a casing string, the total compressive load must be checked to prevent casing yield. For API casings, the compression rating is equal to the tensile rating and an axial compression design factor of 1.0 is appropriate. However, if high compressive loading exists, the connection may be the weak point. (Consult Chapter 17.) Sources of compressive loading at the wellhead include the following [47]: • Weight of wellhead and BOP; • Weight of additional casings hung-off in wellhead (excluding liners); • Production tubing; • Overpull for any buckling requirements; • Additional loading due to temperature and pressures. EPT Drilling
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A-Section
Weld Weld
Base Plate
Surface Casing
Weld Weld Cement Conductor Pipe
Surface Casing
BPAD003_151.ai
Figure 15.20. Base Plate Load Distribution
If the total compressive loading exceeds the tensile yield strength of the casing or connection1415 then a base plate should be used to distribute the load to an outer casing. Figure 15.20 shows the wellhead load path with a base plate. Typically the base plate will be designed with a DF≥2.0 of the total compressive load to account for any deficiencies in load-bearing welds16 . To determine the load on each casing, the following can be used: For a tubular of constant cross-sectional area with length L, a constant load Fa , and one fixed and one free end, the axial deformation is
∆L =
Fa L , EAp
(15.70)
from simple Hooke’s modulus theory. 14 This statement assumes identical behavior of the tube in tension and compression. Particularly for CRA materials, both the value and behavior of yield in tension and compression may differ significantly. Fortunately, for the grades of steel used in service as conductor and surface casing, tensile and compressive behavior is close enough to be considered identical. 15 For weld-on connectors, the weld material may be stronger or weaker than the base tube material. Further, local weakening of the base tube can be realized in the head affected zone of the weld. 16 Cement
between two casings can support a portion of the wellhead loading, but for design purposes this support is disre-
garded.
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Assuming the base plate is in simultaneous contact with both the conductor and surface casing, and that the bottom of each casing is immobile, enforcing the condition that the deformations for the conductor (“c”) and surface casing (“s”) are identical, from Equation 15.70, Fac Lc Fas Ls = . Ec Apc Es Aps
(15.71)
The conductor and surface casings are concentrically cemented, and therefore, compressive load is assumed to be distributed along an equivalent length (or depth) of each string. Thus, Lc = Ls .
(15.72)
Additionally, both the conductor and surface casings are manufactured from carbon steel and thus have the same modulus of elasticity, so Ec = Es .
(15.73)
Fas Fac = , Apc Aps
(15.74)
Fac Apc = . Fas Aps
(15.75)
The remaining equation becomes
or
Apc and Aps can be calculated for selected casings, and the maximum load, Fat , is equal to Fac + Fas . Thus two equations with two unknowns can be solved for Fac and Fas . For the load on the conductor, Fac =
Fat Aps Apc
+1
.
(15.76)
.
(15.77)
For the load on the surface casing, Fas =
Fat Apc Aps
+1
These loads should be checked against the tensile rating of the casing to satisfy a DFt ≥1.0. Contact wellhead manufacturer for base plate designs and unification of load checks. If conductor and surface casing annulus is not cemented, a more detailed analysis is required. Section 15.3 for tiebacks provides the method for uncemented load distributions. See also [47].
15.5
Cuttings Re-injection
Designing casing for proposed use with cuttings re-injection disposal operations introduces a unique set of issues. The objectives of the section are to provide the reader with the following: 1. An overview of typical re-injection annulus requirements and an outline of the different features that play an important role; EPT Drilling
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2. Understanding of the various issues involved in the design of cuttings re-injection annuli; 3. Simple calculation methods useful for front-end engineering studies and preliminary designs. This section is particularly aimed at the impact on casing design of annular cuttings re-injection operations. The various calculation procedures described below are not adequate in themselves to ensure a rigorous design. However, they should permit the development of a robust initial design.
15.5.1
Description of Cuttings Re-injection
Re-injection of oil contaminated drill cuttings is a cost effective means of complying with environmental legislation concerning discharge of oily wastes. The ground cuttings slurry and waste fluids are typically re-injected through the 13-3/8 in. × 9-5/8 in. casing annulus into fractures created within the host formation. Operations are usually batch by nature and carried out at low pump rates (2.0 to 8.0 bpm). These kinds of operations have been carried out all over the world, with disposal into many different types of strata.
15.5.2
Features Required in a Design
The design of casing strings that are to be utilized as cuttings re-injection routes must take into account all the anticipated combinations of temperature, pressure, loads, etc., that the annulus may encounter during its operational life. In addition to the customary casing design requirements of considering the nominal burst, tensile and collapse loads to which a string may be exposed, a cuttings re-injection casing design has to address the issues discussed below. Further details can be found in the cuttings re-injection guidelines produced by the E&P Forum [35].
15.5.3
Erosion
Erosion is primarily the wastage of material due to mechanical effects caused by a flowing environment. Full details of the different erosion mechanisms and methods for predicting material losses are discussed in Erosion Guidelines on Allowable Velocities for Avoiding Erosion and on the Assessment of Erosion Risk in Oil and Gas Production Systems [80]. In the case of cuttings re-injection there are two main areas of concern regarding the potential for erosion: 15.5.3.1
Wellhead Erosion
One item susceptible to excessive erosional wear during cuttings re-injection operations is the injection point at the wellhead. A review of cuttings re-injection operations on the Gyda platform [95] indicated that the greatest erosional concern was with the 9-5/8 in. casing hanger, within the wellhead. The hanger was immediately opposite the re-injection port and a degree of erosion was anticipated. Simulation consisted of the jetting of a sand slurry (the worst case) against a sample of the steel similar to that used in the hanger, under controlled conditions. This work indicated that, at worst, for the 30,000 bbl disposed of, wall thickness erosion of approximately 5% might occur. This amount of localized erosion was not felt not to have materially changed the functionality of the hanger and was therefore acceptable. The rule of thumb now applied on Gyda is 0.05 mm of erosion per 1000 bbl injected. EPT Drilling
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15.5.3.2
Re-injection Point Erosion
Re-injection points in the wellhead, may result in the slurry directly impinging on either casing hangers or the casings themselves. Sirevag and Bale [86] carried out an extensive investigation of the effects of waste disposal on wellhead erosion. The following rule-of-thumb relationship was derived for erosional wear
tE = 3.57 × 10−6 csnd tv 2.1 ,
(15.78a)
tE = 43.27 × 10−6 csnd tv 2.1 ,
(15.78b)
tE = 1099 × 10−6 csnd tv 2.1 .
(15.78c)
or in Hybrid units,
or in SI units,
where t is injection time in hours. As an example calculation [86] for a velocity of 19.68 ft/s, a sand concentration of 10 % and 400 injection hours, the loss of wall thickness is estimated to be tE = 3.57 × 10−6 × 10 × 400 × (19.68)2.1 = 0.0745in.
(15.79)
Tests run with funnel viscosities (FV) of 40 and 120 seconds, and a velocity of 23 m/s (75 ft/s) indicate that the 3 fold increase of FV reduces the wear by half. This fluid viscosity effect appears to be strictly valid for velocities as low as 10 m/s (33 ft/s). However, Equation 15.78 is only valid for a slurry funnel viscosity (FV) above 40 seconds. The method adopted for monitoring erosion was to construct a spreadsheet, similar to that given in Table 15.8, which is updated daily at the rig-site. This is a useful approach as it almost guarantees that the re-injection service company will keep detailed daily records and perform the required slurry QA/QC tests when appropriate. Experiments indicate that most standard steel grades will suffer the same level of erosional attack for conditions where erosion is the dominant material degradation mechanism. This theoretical approach should be supplemented by frequent wellhead inspections of the injection point through a lubricator port. These inspections could employ some form of boroscope technology, micrometer action or even some form of impression tool, with the intent of measuring erosion scar depth and geometry. It is also possible to have a dummy wellhead or coupons in the injection line, which may be periodically examined. The angle of impact and flow path geometry are important features of erosional effects. For example, in the case of steel, the worst case impact angle for erosion is 20◦ to 30◦ . The use of casing slips with a deflector shroud or “skirt” has been suggested in order to protect the inner casing from the injected fluid. In some of BP’s re-injection operations, Gulf of Mexico specifically, injection at the wellhead has made use of a valve removable plug, see Figure 15.21. This plug is a directional nozzle that forces the slurry downwards, and may be periodically removed and examined for wear. Sirevag and Bale [86] examined the use of directional nozzles. Although not documented, they indicate that nozzle wear EPT Drilling
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Table 15.8. Typical Record of Slurry Batch Properties and Cumulative Erosion Date
Time (hr)
Slurry SG
Sand (%)
Volume
Average
Batch
Pump
Pumped (bbl)
Wellhead Velocity
Erosion Value (in)
Time (hr)
(ft/s) Cumulative Erosion to Date (in) 0.0030421 10/10
22.10
1.78
10
97.49
8.20
0.0000297
1.00
11/10
14.07
1.53
18
75.48
4.92
0.0000183
1.00
12/10
16.35
1.42
15
50.32
4.27
0.0000113
1.00
13/10
15.16
1.27
8
81.77
4.92
0.0000081
1.00
14/10
1.50
1.45
15
84.91
5.87
0.0000221
1.00
14/10
10.41
1.33
18
75.48
4.17
0.0000129
1.00
14/10
17.23
1.48
18
81.77
4.89
0.0000180
1.00
15/10
2.26
1.12
6
84.91
5.35
0.0000072
1.00
15/10
15.40
1.51
18
69.19
4.79
0.0000173
1.00
15/10
20.05
1.57
15
81.77
4.79
0.0000144
1.00
16/10
11.08
1.36
13
88.06
4.79
0.0000125
1.00
16/10
16.02
1.23
1.3
84.91
5.35
0.0000015
1.00
16/10
21.30
1.10
1.3
91.20
5.28
0.0000015
1.00
17/10
8.30
1.20
5
84.91
4.36
0.0000039
1.00
17/10
11.35
1.14
3
75.48
4.36
0.0000024
1.00
17/10
16.10
1.29
4
84.91
4.36
0.0000032
1.00
Erosion from this Spreadsheet (in) 0.0001841 Cumulative Erosion to Date (in) 0.0032262
is very high. The method eventually employed by Statoil to reduce erosion was to limit the injection rate to 1 bpm per injection point and to use a wear bushing to protect the valve threads during these operations. If cuttings re-injection is not a retrospective consideration, it is also possible to have the wellheads designed such that the re-injection point alignment is vertical. This provides an uninterrupted path to fluid flow at the re-injection point and minimizes, if not eradicates, erosional problems at the wellhead. It is extremely important that each particular field cuttings re-injection application give careful consideration to the potential for erosional wear at the wellhead entry point, as different field applications may result in different amounts of wear. For example, waste slurry produced from a field with many horizontal wells drilled in a sandstone material will have a far more abrasive effect than a similar volume produced EPT Drilling
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Pump pressure would dictate how much fluid could be reinjected
Valve ID depends on the casing outlet size that is available.
BPAD003_157.ai
Figure 15.21. Schematic of Valve Removable Re-injection Nozzle
from vertical wells consisting of mostly shaly material, i.e., volume considerations alone are not sufficient. 15.5.3.3
Annular Casing Erosion
For the particular situation arising from the re-injection of drill cuttings wastes, two primary mechanisms could apply to casing erosion, depending upon the water/seawater quality: • Pure solids erosion by a non-corrosive fluid carrying solid particles; • Erosion-corrosion by a corrosive medium containing solids. Erosion-corrosion occurs in environments that have the potential to be both erosive and corrosive. The erosion can either be independent, in which case the total wastage is the sum of the wastage produced by each mechanism in isolation; or synergistic, in which case the total wastage is greater than the sum of the individual processes. For the cuttings re-injection operation, synergy is unlikely17 , such that the total material loss is determined by the sum of the erosion and corrosion rates. Erosional models have been proposed for pure solids erosion by several different R&D programs [80]. One of these models, the “RCS Model”, was derived from liquid slurry testing and hence is the most appropriate to apply to cuttings disposal operations. This model states that
tE = 8.7 × 10−3 m ˙ 17 Synergy
v 2.5 t , D2
(15.80a)
is more likely in corrosion processes involving a filming mechanism.
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or in Hybrid units,
tE = 169.6 × 10−3 m ˙
v 2.5 t , D2
(15.80b)
or in SI units,
tE = 241.26m ˙
v 2.5 t . D2
(15.80c)
where t is injection time in minutes. For the disposal of drill cuttings waste a velocity limit, within the casing annulus, of 200 ft/min (1.0 m/s) should be applied to maintain an erosional wastage below 0.1 mm (assuming 100,000 barrels cuttings reinjection). This is equivalent to an injection rate of 2.0 bbl/min in the case of injection into a 13-3/8 in.95/8 in. casing annulus. If velocities above this level are to be used, then further evaluation of the particular circumstances would be necessary. It is usually the case that wellhead erosional concerns will override any casing annuli erosional limitations. As indicated above, slurry properties vary considerably, depending upon which formation type and hole size is currently being drilled. It would therefore be advisable to consider each implementation of cuttings re-injection as a specific case and the erosion/corrosion rates examined accordingly.
15.5.4
Corrosion
This section should be considered in conjunction with Chapter 18. The primary corrosion risk with cuttings re-injection operations is that associated with the oxygen content of the seawater used to form the slurry. Raw seawater has a dissolved oxygen content >6 ppm, with the actual content dependent on the temperature and salinity. In an open system the oxygen content decreases with increasing temperature. However, for a closed system such as downhole re-injection the oxygen content at all temperatures is determined by the initial oxygen content (concentration at the wellhead). In this case the oxygen is kept in solution by the high pressures applied to inject the slurry. Corrosion rates for raw seawater are likely to be excessively high18 . The resultant level of material loss is therefore unacceptable. The corrosion rate can be reduced by lowering the oxygen content of the seawater. Guidelines for seawater quality to minimize corrosion effects on carbon steel have been issued [70]. This section outlines some practical methods for minimizing seawater corrosivity. 15.5.4.1
Use of De-aerated Seawater
Whenever possible, de-aerated seawater should be used. This can often be the treated seawater used for reservoir pressure maintenance. However, oxygen can reenter the system during the slurrification process. Consequently, the level of oxygen in the slurry should be determined after slurrification, and oxygen scavenger added to remove unacceptable levels of dissolved oxygen. Sodium sulphite is typically used as an oxygen 18 For
the Andrew field at 110◦ C and a predicted injection pressure of 1,300 psi the predicted corrosion rates were well in excess of 50 mm/yr, or 0.14 mm per day of continuous injection.
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scavenger, with approximately 10 ppm of sodium sulphite being used to remove 1 ppm of dissolved oxygen (6 ppm ammonium bisulphite for 1 ppm oxygen).
15.5.4.2
Raw Seawater
As stated previously, raw seawater leads to unacceptable corrosion rates. The oxygen content can be reduced by adding oxygen scavenger as described above. The oxygen scavenger should be added down stream of the slurrification process. Although the oxygen scavenger requires a residence time of two to three minutes to work, the slurry pump rate is slow allowing ample reaction time before the higher temperature/high corrosion rate zones are reached. The opex cost implication of such a treatment is low. For the Andrew re-injection field case, the maximum acceptable pump rate is approximately 8 bpm. Typically drill cuttings will be disposed of in batches at an average daily injection volume of 1,500 bbl. Assuming that the seawater contains 10 ppm dissolved oxygen, 100 ppm of oxygen scavenger will be required to remove the oxygen. This equates to 25 litres/day of oxygen scavenger which at £0.35/liter incurs a cost of approximately £10/day. With any seawater based system, microbial activity can lead to corrosion. Contamination of the annulus with bacteria while pumping the slurry will allow colonization of the steel during any static period and the potential for microbiologically induced corrosion (MIC). Therefore, in all cases the risk of MIC should be minimized by the use of a biocide. Seawater from a water injection system will have been chlorinated. Although the chlorine used will control some of the microbial action this should be supplemented with regular biocide treatments. Raw seawater will have a greater propensity to cause MIC. Therefore, in both cases, biocide should be used to minimize the risk from MIC. Continuous biocide treatment is unnecessary. However, regular biocide treatment should be undertaken. A good approach would be to treat the last two hours of slurry re-injection each day with 500 ppm of biocide by volume. This will ensure that the risk of MIC is minimized during the static periods when slurry re-injection is suspended. Continuing the Andrew field case example, the maximum pump rate is 480 bph. In order to achieve 500 ppm of biocide, for the last two hours of re-injection each day, approximately 76 liters/day of biocide are required, which at £1.5/liter incurs a cost of £115/day. Further corrosion activity may take place external to the casing, and this may be exacerbated by interaction of the various chemicals that have been introduced with the waste slurry into the formation fluids.
15.5.5
Cementing
A good casing cement job on both re-injection strings is critical to the success of any cuttings re-injection program. In addition, the location of the injection shoe and tops of cement (TOC) are also important factors affecting the success rate of cuttings re-injection. Good cementing practices include centralization, optimized cement placement with weighted spacers, a stable cement slurry, quality sampling, pipe movement, cement strength and quality testing. EPT Drilling
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Good Cement
Bad Cement
Washout
Centralisers
Good Centralisation 80% Stand-Off
Poor Centralisation < 70% Stand-Off BPAD003_158.ai
Figure 15.22. Schematic Indicating the Use of Centralizers
15.5.5.1
Location of the Shoe
The location of the re-injection shoe will depend on the lithology, flexibility of the drilling program and formation fracture gradients. As far as cementing is concerned, the deeper the injection shoe and the longer the cement column, the less chance of breaching to surface while re-injecting cuttings slurry. Placing the shoe at or just below a competent low permeability horizon will also improve the chances of a good cement job. 15.5.5.2
Centralization
Good centralization of the injection shoe is essential. Poor centralization can result in communication during injection up the narrow side of the annulus, where poor mud removal often occurs. Washouts can be a particular problem and extra care and attention is necessary when choosing the placement of the centralizers (see Figure 15.22). A minimum stand-off of 70% is required (preferably 80%). Refer to the BP drilling manual for calculating stand-off and the stand-off guidelines. Solid blade centralizers, although more expensive than bow strings, are less likely to be damaged while running in hole and while rotating during cementing. A calliper (preferably mechanical) should be used to determine washout location and hole volumes. This will not only help determine the preferable location of centralizers (in gauge hole), but also assist in determining the likely TOC and aid displacement. EPT Drilling
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15.5.5.3
Pipe Movement
If pipe movement, particularly rotation, can be achieved during the cement job, this will assist in good mud removal and improve the chances of good cement placement. 15.5.5.4
Spacers
A stable, weighted spacer is recommended for any critical cement job so as to improve the likelihood of efficient mud removal. Washes or scavenger fluids can be employed ahead of the spacer if the hydrostatics permit. A spacer midway in density between the mud and cement will significantly aid placement due to the buoyancy effect. A spacer more viscous than the mud and less viscous than the cement will also aid the displacement. Conditioning and thinning the mud prior to cementing is advisable to allow for good mud removal and displacement. An oil-based scavenger fluid stage, ahead of the 9-5/8 in. cement slurry, has been employed on some Norwegian wells. The scavenger stage is included to space the oil-based fluid lies adjacent to the proposed re-injection zone. When water-based scavengers have been used, reaction with the formation19 has resulted in high fracture initiation pressures, even to the point where re-injection was not possible. Consideration should therefore be given to the type of formation and its compatibility with the type of spacers programmed. 15.5.5.5
Tops of Cement
The lead slurry TOC for the re-injection shoe casing string should be at least 500 m (1,500 ft) above the shoe (preferably to surface). The tail slurry TOC should be at least 150 m (450 ft), preferably 300 m (900 ft). The longer the length of cement column, the greater the chance of a competent cement sheath. This cement sheath minimizes the potential for channeling and reduces the possibility of excessive fracture height growth resulting in communication with the 20 in. × 13-3/8 in. annulus. In the particular case of the Gyda re-injection wells, for example, the re-injection shoe casing string is always cemented to surface. The TOC on the casing string inside and below the re-injection shoe must be balanced between two extremes. Too high introduces the risk of cementing inside the re-injection shoe; too low introduces the risk of re-injecting into a non-preferred horizon. A recommended maximum calculated TOC for this string is 100 m (300 ft) below the re-injection shoe. On a long casing string, channeling and slurry excesses may result in cement reaching the previous shoe (making re-injection difficult). In cases where this risk exists, a port opening tool may be used to circulate out any excess cement. The tool should be placed exactly where the TOC is required. Under no circumstances should these treatments be over-displaced. Otherwise, the risk of cementing inside the re-injection shoe is significantly increased. Alternatively, if there is a chance of cement stringing up into the surface casing from the intermediate/long string cement job, connect onto the annulus and initiate injection after the cement displacement, so as to ensure that there is no cement blockage. 19 Water
based spacers may cause swelling of interstitial clays.
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TOC
> 300 m Tail Slurry
Re-Injection Shoe
> 100 m
TOC
BPAD003_159.ai
Figure 15.23. TOC Schematic for Cuttings Re-injection Well
15.5.5.6
Cement Mixing, Density and Volume
Generally speaking a simple 1.92 SG (16 lb/gal) cement slurry is best, although some retardant and possibly fluid loss additive (for high permeability sands) may be necessary. Batch mixing of the cement will ensure the creation of a more homogenous slurry. If batch mixing cannot be readily achieved, then a recirculating type cement mixer is a minimum requirement. In areas where the injected formation strength is quite high, slurry densities greater than 1.92 SG (16 lb/gal) may give necessary additional compressive strength. The exact required slurry SG may be estimated from examination of FITs and LOTs from nearby wells. 15.5.5.7
Cement Sampling and Testing
The quality of sampling and laboratory testing is often the key to the success or failure of any cementing operation, but is particularly important for a critical cement job such as a re-injection shoe. Evidence of appropriate laboratory testing using actual rig samples is required. The samples must be carefully collected, EPT Drilling
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packaged/prepared and transported to prevent contamination or aeration. In addition to standard laboratory tests, the service company should test the slurry for stability using the BP settlement test procedure. As a rule of thumb for critical jobs such as these, whether deviated or not, the reduction in height of the cement column must be less than 5 mm; with a change in density gradient from top to bottom of no more than 0.1 SG. 15.5.5.8
Contingencies
As with all cementing jobs, the inclusion of contingency barriers is a useful if not necessary precaution. For a cuttings re-injection well, there should be at least two cement barriers between the re-injection shoe and surface, or zones requiring isolation. At least one additional string should be cemented above the re-injection string. If poor hole condition is expected on the re-injection string and cement to surface is not likely, or if the previous string is not cemented, then consideration should be given to a two stage cement job. 15.5.5.9
Special Cases
Isolation of potential problem formations such as water aquifers and producers may be beyond the capability of a standard single stage cement job. In such cases consideration should be given to multi-stage cementing tools, where excess cement can be circulated out if necessary, or to the use of cement inflated external casing packers instead of a standard cementing procedure. If cuttings re-injection operations are anticipated, the possibility of running a CBL/CET log should be considered to obtain information regarding the casing/cement/formation bond. It could be that the use of such tools/logs, in the absence of any additional data, will indicate that re-injection operations could cause problems and therefore be useful as a technique for the “ranking” of disposal wells in some preferential order.
15.5.6
Annular Clearance
Many developments now have the requirement for 6-5/8 in. drill pipe, resulting in the production casing string being a combination of 10-3/4 in. and 9-5/8 in. casing. This leads to a reduced annular clearance above the 13-3/8 in. shoe, which is the normally intended target for re-injected cuttings. A reduced annular clearance will present two particular concerns. The first is pressure loss down the annulus, consisting of friction loss or entry/exit head loss at the couplings. The second concern is the possibility that the annulus may be plugged during re-injection operations or static periods. Work performed at Sunbury [83] indicates that friction losses during re-injection in hybrid casing strings, can be expected to be roughly double that normally encountered. For example, in the case of a typical Miller disposal annulus, friction loss was calculated to increase from 120 to 250 psi. Further analyses also indicated that the friction pressures calculated were extremely sensitive in this size annulus to the yield point of the cuttings slurry. Special clearance couplings are readily available and in the particular size/type of casing utilized on Bruce, for example, the 10-3/4 in. special coupling would have an outside diameter of 11.268 in. If this coupling were used it would lead to an increase in annular clearance of 0.252 in., from 0.3215 in. to 0.5735 in. In the case of the more usual 9-5/8 in. casing this clearance would generally be 0.883 in. (all assuming EPT Drilling
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centralized casing.) It should be noted, however, that the special clearance connectors have reduced tensile yield strength. For 10-3/4 in. casing, the drop in connection axial yield capacity is from 1,165 kips (standard coupling) to 889 kips (special clearance). Annulus plugging is difficult to predict. Current practices within BP appear to have avoided this problem. However, such serendipity is far from ideal. One operator in the North Sea has encountered difficulties plugging annuli and problems have also been known to occur in the Gulf of Mexico. On the whole these are avoidable by good re-injection practices, i.e., avoiding slurry/water interfaces when a re-injection well is static, excellent slurry QA/QC including particle classification and displacement of annuli to OBM when intending to suspend disposal operations for a substantial period, such as the completion phase of one well and spudding of the next.
15.5.7
Burst and Collapse
Cuttings re-injection treatments are, by their very nature, are complex and hazardous. Cuttings re-injection is a form of hydraulic fracturing, an operation that requires detailed string and wellhead design before safe implementation can be assumed. When considering burst and collapse requirements for re-injection casing (see Chapters 8 and 9), several factors must be considered. The normal load cases will apply but it is important to note that fracture propagation pressure must be achievable at the casing shoe throughout the re-injection well’s use. This requirement may be estimated from the fracture gradient data in a development program or from a LOT performed at the shoe depth. The LOT value may be high and reductions in casing strength due to casing wear, erosional factors and corrosion strength reduction must also be taken into account. The governing equation for cuttings re-injection operating pressures is ptrSurf = pf rN et + pf r + pf ric − ph .
(15.81)
The probable wellhead treating pressure may be calculated by substituting into Equation 15.81. The pf rN et and pf r values may be combined and their value taken as the fracture gradient given on a drilling program pore-pressure and frac gradient plot. This may be refined if LOT or FIT data exist. The frictional loss down the annulus pf ric is usually minor but may be calculated if required. Finally, when considering the value of the hydrostatic head of the slurry, it is probably best to consider a range of values as described in the example below [84]. The casing design currently adopted for Miller is summarized below in Table 15.9. The 13-3/8 in. casing shoe is set at 6,830 ft/TVD/BRT. The prognosed formation fracture gradient at the 13-3/8 in. shoe depth is taken to be approximately 0.78 psi/ft, leading to a formation breakdown pressure of 0.78 × 6, 830 = 5, 327 psi. From Equation 15.81 the maximum surface pressure required to breakdown the formation at the 13-3/8 in. shoe with 1.3 SG cuttings slurry is
ptrSurf = (pf rN et + pf r ) + pf ric − ph = 5, 327 − (6, 830 × 1.3 × 0.433) + 250
(15.82)
= 1, 733 psi. EPT Drilling
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Table 15.9. Miller Casing Design Casing
Grade
Weight
Collapse
(lb/ft)
(psi)
Burst (psi)
Connector
Shoe (ft/TVD/BRT)
18-5/8
K55
87.5
630
2,250
Buttress
1,615
13-3/8
N80
68.0
2,260
5,020
Buttress
6,830
10-3/4
L80
51.0
3,220
5,860
New Vam
6,430
9-5/8
L80
47.0
4,750
6,870
13,000
7
L80
29.0
7,020
8,160
Vam Ace
6-5/8
SM2535
20.0
14,150
Table 15.10. Maximum Surface Pressures due to Burst at the Re-Injection Shoe Slurry SG Maximum available surface pres-
1.2
1.3
1.4
1.5
1.6
3,738
3,542
3,246
2,950
2,655
sure (psi) SF 1.1 The casing burst load at the 13-3/8 in. shoe is, (pf rN et + pf r )−pp , or 5, 327−(6, 830 × 0.45) = 2, 254 psi and the safety factor is 5, 020/2, 254 = 2.23. The approach taken is to calculate the maximum allowable surface pressure at all points down the annulus that lie within the burst rating envelope. In this way the weak point and limiting pressure may be identified. Taking into account the current BP DFb = 1.1, assuming a slurry SG of 1.3 and seawater pore pressure behind pipe, the maximum allowable wellhead pressure at the re-injection shoe is
Max allowable WH pressure =
Burst rating − ph + pp − pf ric DFb
= 5, 020/1.1 − (6, 830 × 1.3 × 0.433) + (6, 830 × 0.45) − 250
(15.83)
= 3, 542 psi. This may be repeated for various slurry SGs as shown in Table 15.10. It is simple to construct a spreadsheet calculating maximum wellhead pressure available for various depths and slurry SGs, a summary for Miller is given in Figure 15.24. Clearly, the weakest point is the re-injection shoe itself, and with the aid of Figure 15.24 a maximum wellhead pressure limitation may be set. In the case of the burst load case, it is rarely a limiting factor in the case of cuttings re-injection operations. As can be seen from the casing design given in Table 15.9, the inner casing string is a hybrid of 10-3/4 in. and 9-5/8 in. casing, the 10-3/4 in. casing string shoe is set at approximately 6,430 ft/TVD/BRT. Assuming a safety factor of 1.0 for collapse, seawater behind the production casing and considering the crossover point EPT Drilling
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5000
4000
SG 1.2
3500
SG 1.3 3000
(psi)
Maximum Wellhead Pressure
4500
SG 1.4 SG 1.5
2500
SG 1.6 2000 0
2000
4000
AnnularDepth
6000 (ft) BPAD003_160.ai
Figure 15.24. Maximum Wellhead Pressure Variation with Depth and Slurry SG, Miller Example
Table 15.11. Maximum Surface Pressures due to Collapse at the Crossover Point Slurry SG Maximum available surface pres-
1.2
1.3
1.4
1.5
1.6
2,523
2,244
1,966
1,688
1,409
sure (psi) SF 1.0 to be the weakest point in the string, then the maximum wellhead pressure that may be used for 1.3 slurry SG can be calculated as
Max WH pressure, Collapse =
Collapse rating − ph + pp − pf ric DFc
= 3, 220/1.1 − (6, 430 × 1.3 × 0.433) + (6, 430 × 0.45) − 250
(15.84)
= 2, 244 psi. Again it is simple to construct a spreadsheet of the maximum wellhead pressure available for various EPT Drilling
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3500
2500 2000 SG 1.2 1500
SG 1.3
1000
SG 1.4
(psi)
Maximum Wellhead Pressure
3000
SG 1.5 500 SG 1.6 0 0
2000
4000
AnnularDepth
6000 (ft) BPAD003_161.ai
Figure 15.25. Maximum Wellhead Pressure Variation with Depth and Slurry SG, Miller Example
depths and slurry SGs, a summary for the Miller case is given in Figure 15.25. If a production well is to be simultaneously gas lifted while undergoing re-injection operations, although this is not recommended, the ∆p across the production casing can be excessive. Indeed, a great deal of caution should be taken in choosing re-injection well candidates as the potential to retain some annular pressure long term exists, even after re-injection operations have been completed. This may in some way limit the available engineering functionality of the producer/injector.
15.5.8
Seal Integrity
The requirement for an effective seal to be provided by the wellhead and casing connectors is also an important consideration. Compatibility of the slurry waste and its additives, with seals, should be investigated. EPT Drilling
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15.6
Casing and Tubing Machined Crossover Design Guidance
Crossovers are notorious problem design components, partly because they are often last-minute procurement “one-off” items and do not receive the same level of assurance of technical integrity as bulk tubular goods. The latter have well established processes in place, “one-offs” do not. The problems occurring are mostly the same as for other tubulars, with a few extra considerations, as described in the following sections.
15.6.1
Excessive Stress
The crossover should generally be at least equal in performance to the weaker of the components it joins. The adequacy of the connecting tubulars is demonstrated by design programs. However, these programs, e.g., StressCheck, do not consider the details of crossovers. There are calculation methods available for crossovers but these can be lengthy and complicated so a separate guideline, GIS 02-203 (Revision 6) Specification for OCTG Crossover Connectors [64], has been written to minimize additional (and potentially difficult) calculations. The guideline allows one to base the performance properties of the crossover on the untapered diameters, wall thicknesses and crossover yield stress and compare them with the standard casings in this manual. Where calculations are considered necessary, e.g., to ensure that a supplier understands the expected service conditions, the calculations should include both the API uniaxial burst calculation and a triaxial stress calculation; the latter is not a substitute for the former.
15.6.2
Non-Uniform Material Properties
Crossovers usually begin life as a solid bar, which is often thick. The material properties of the machined crossover will depend on from what radius of the solid bar it was cut. To minimize property variation, adequate reduction ratio from “as cast” to forged bar stock is required, and tensile test samples must come from areas of the bar stock relevant in location and orientation to the eventual machined crossover.
15.6.3
Incorrect Connection
The section on connections in the casing design manual applies equally to crossovers. An extra requirement for crossovers is to keep changes of section away from the connection to avoid stress concentrations additional to those considered during the original design testing and rating of the connection.
15.6.4
Stress Concentrations
Each time there is a discontinuity of geometry (e.g., a rapid change in diameter, the machining of an O-ring groove, the cutting of a slot, the machining of a radius, the machining of a thread, the drilling of a hole, the creation of a shoulder) the effect is to raise the stress local to the discontinuity and a stress concentration or “stress raiser” will be the result. These can be particularly troublesome for shock loads, for example while running. The dimensional guidelines in [64] minimize stress concentrations and avoid superimposing one stress concentration on another. In addition, if there is a rapid discontinuity of stiffness where the crossover mates to the next component, the boundary serves as a stress raiser. This is seen when thread specifications limit the wall thickness onto (or into) which the threads are cut. Do not simply thicken the wall of the EPT Drilling
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crossover and expect the crossover-to-next-component boundary to be stronger. If a coupling/box thread wall is radically thicker than the pin to which it joins, failure is encouraged at the pin side of the boundary.
15.6.5
Fatigue
Repeated cyclic loading is capable of failing a component even if the stresses are less than the expected failure stress. Significant cyclic loading is not normally seen in casing design, although it could occur in short cycle time water-alternate-gas injection wells, but it can occur in tubing, perhaps as a result of violent slug flow, or vibration from a downhole pump. Minimizing stress concentrations by following the guidelines in [64] should avoid fatigue being more of an issue for crossovers than for casing and tubing.
15.6.6
Corrosion
Corrosive effects, given time, can fail the crossover, either by stress corrosion cracking, chloride attack, removal of material to cause a stress concentration or simply raising the nominal stress via material removal. Seek specialist advice if the crossover material is different from the pipe body material as there is a risk of galvanic corrosion between dissimilar materials. Similarly, if the pipe body is plastic coated internally, it is logical to have a similar finish on the crossover. The same material selection guidelines apply to crossovers as to casing and tubing. Unfortunately, this may mean that crossovers of appropriate material have a long lead time so crossovers need to be considered in the same light as other tubulars in the design and procurement process.
15.6.7
Material and Geometry Vulnerable to Abrasion
Where the crossover joins two different diameters of pipe in a flowing situation, there may be areas of high local turbulence. Should the flow have some solids content, abrasive wear rates can be damaging. Typically, thick-walled “flow couplings” are added at points of expected turbulence better to withstand abrasion. Ensure that the crossover has similar resistance, and ensure gradual tapers to reduce turbulence.
15.6.8
Component Weakened by Pre-use
Tubing crossovers are often used repeatedly, and over-enthusiastic use of rig tongs, overtorquing, hammering or corrosion during storage can contribute to failure. Any crossover, new or used, should be inspected before use and the service history of used crossovers should be available for review–the crossover may have spent time in a sour environment for which it was unsuited.
15.6.9
Design Control
Crossovers are just as important as the rest of the string, although as an item they may seem relatively cheap. The consequences of failure in service or while handling are the same as for other downhole tubulars. Crossovers need the same attention to design, procurement and handling as the rest of the string. Of particular concern for crossovers are arbitrary design changes (e.g., changes to material specification, or EPT Drilling
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modifications to geometry) to accommodate the convenience or stock availability of the machine shop. Crossovers, like other tubulars, need to be included in the engineering process of demonstrating integrity.
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Chapter 16
Tubular Design Reliability 16.1
Introduction
In 1990, Payne and Swanson [81] presented the concepts of probabilistic design to the drilling community in a conceptual technical publication. The paper examined the basis of working stress design (WSD) as embodied in design/safety factors and showed how concepts of probabilistic design might be applied to oil well casing strings. In the years following, several operators have implemented principles of probabilistic design (or its variations) to optimize design and reduce costs without compromising safety and reliability. Mobil implemented Load and Resistance Factor Design (LRFD) software to design tubulars on a companywide basis, as described in the publications by Lewis et al. [51] and Maes et al. [54]1 . Shell’s efforts in this area consist of Bradley’s [19, 20] early work on the effects of casing wear on internal pressure capacity and the more recent work presented at an SPE workshop based on Risk Based Design [46, 90, 44, 72]. The papers by Adams et al. [4] and Parfitt and Thorogood [71] summarize the work by BP while Exxon’s efforts are described by Banon et al. [13].
16.2
Working Stress Design
Conventional working stress design maintains a specific margin between the maximum anticipated load to which a tubular will be subjected and the resistance of the tubular to that load. The anticipated load is usually based on the worst value that can theoretically originate during given operations. For example, the worst load on a surface casing string might be the internal pressure at the casing shoe during a pressure test. Correspondingly, the appropriate resistance of the tubular would be the minimum internal yield pressure rating as given by the manufacturer or an appropriate industry standard such as the API or ISO. The margin between the maximum anticipated load and the published rating is the safety factor, Safety Factor =
Rating . Maximum Anticipated Load
(16.1)
Working stress design of a tubular is based on the following steps: 1 Mobil’s
design philosophy and software has, since the merger with Exxon, been adopted by the combined ExxonMobil.
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Figure 16.1. Working Stress Design
1. Determining the maximum anticipated load or load combination, and 2. Determining the tubular whose rating satisfies Equation 16.1. The allowable safety factor, often termed the design factor, is determined largely on an historical basis. Maximum anticipated loads are determined from scenarios for well operations, as embodied, for example, in other chapters in this manual. The tubular which satisfies the required rating is determined from published ratings. These ratings are supplied by the tubular manufacturer or in accordance with API TR 5C3 or ISO TR 10400 [9]. Figure 16.1 illustrates this concept and reveals the following important underlying consequences of this approach: • If the safety margin equals the design factor, all tubulars that have a rating R or greater are acceptable design candidates while tubulars whose rating is less than R are unacceptable. • The implied probability of failure of a tubular whose rating is less than R is 100% while the implied probability of failure when its rating is greater than R is zero. • There is no quantitative measure of safety. For example, a design with a safety factor of 1.1 is less safe than a design with a safety factor of 1.2, but by how much? • Calculations typically require that conservatively derived, theoretically maximum loads never exceed conservatively derived minimum ratings. The margin resulting from this procedure may be excessive.
16.3
Probabilistic Design
Working stress design promotes over-design due to the infrequent, if ever, occurrence of the assumed high load case and the inherent conservatism in the published ratings of tubulars. Probabilistic or reliability based design more accurately accounts for both the actual field loads and the actual tubular performance EPT Drilling
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Figure 16.2. Overview of Probabilistic Design
properties during the design process. As a result, probabilistic design more accurately achieves the most economic fit-for-purpose design. In the most general applications of probabilistic design, the load and the tubular performance are treated as random variables described by statistical probability distribution functions (PDFs). Any given load or resistance has a specific probability of occurrence. This is illustrated in Figure 16.2 where the curve on the left describes the statistical distribution of the various loads that may occur and the curve on the right describes the distribution of the tubular’s performance properties. These PDFs are developed based on field load histories and actual test results on tubular performance. Reliability methods are then used to combine these distributions and quantify the reliability of the design under specified conditions. The application of probabilistic concepts to OCTG design was discussed by Payne and Swanson [81]. Although this publication is frequently referenced as one of the early papers in the field, fundamental papers on probabilistic tubular design issues were published as early as 1945 [25]. Not only is probabilistic OCTG design approach not new; rather it is a mature discipline of engineering design [27]. An important conclusion of Payne and Swanson [81] was that excessive conservatism is inherent to the design of tubulars since they are designed for severe, and sometimes unlikely loads, simultaneously using overly conservative design limits for the tubulars. The desire for accurate probabilistic formulation results in an increased emphasis on improved understanding and accurate quantification of material and dimensional tubular properties and the accompanying performance properties. The approach also includes an increased scrutiny of maximum load conditions. EPT Drilling
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16.4
Comparison of Working Stress and Probabilistic Approaches
Figures 16.1 and 16.2 allow comparison of the major similarities and differences between the working stress and probabilistic design approaches:
16.4.1
Similarities
• Both methods attempt to maintain resistance greater than load. Neither approach is inherently unsafe. Rather, the approaches differ in their means of expressing risk. • Both systems rely on data/experience. In working stress design, experience is implicit in the design factor. In probabilistic design, the data is handled explicitly in the PDFs.
16.4.2
Differences
• In working stress or deterministic designs, the safety of the design is expressed as a single value, the safety factor. In probabilistic design, the safety of the design is expressed as a single value, the probability of failure (or success). • In working stress design, the safety of a design is binary. The ratio of resistance to load is either greater than the design factor, or it is not. In probabilistic design, a completely safe (e.g., no failure) result is mathematically impossible. Due to the nature of the statistical distributions used to characterize both load and resistance, there will always be some, albeit small, overlap between the load and resistance PDFs. • Probabilistic design is the more quantitative of the two methods. Changes in the load and/or resistance PDF results in a quantifiable change in the probability of failure. Changes in the deterministic load or resistance in working stress design changes the ensuing safety factor, but there is no clear measure of the corresponding change in design risk. A deterministic safety factor of 3.0 is not necessarily twice as safe as a deterministic safety factor of 1.5. • Due to the necessity of building PDFs for both load and resistance, the probabilistic method requires substantially more data than working stress design. • Accurate probabilistic designs are difficult to achieve, as some issues (human factors, unknown unknowns) are difficult to quantify.
16.4.3
Hybrid Approaches
The data collection inherent in probabilistic design is particularly difficult on the load side of the equation. For example, accurate statistics on kicks require data collection on all kicks, not just those of significance. On the other hand, cooperation with a steel mill can produce volumes of data on the tubular dimensions and material properties necessary to determine performance. For this reason, in some instances it may be appropriate to consider a hybrid approach to design where the load statistics are represented by a single (deterministic) value and the performance properties representing a particular limit state are treated statistically. EPT Drilling
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16.5
Probabilistic Description of Performance Properties
There exist two methods for determining design performance properties: • In the direct method, the end result, for example collapse performance, is tested directly and a design rating is achieved by applying statistical principles directly to the ensemble of collapse test data without regard for the underlying physics of the behavior. • In the indirect, or synthesis method, one indirectly determines design performance by applying production quality statistics of input variables to a suitable limit state predictive formula.
16.5.1
Performance Properties by the Direct Method
The direct method for characterizing a performance property consists of choosing random specimens and measuring the performance property of interest for these specimens. In statistical terms, the set of randomly chosen specimens is known as the sample and the set of all the specimens is known as the population. The number of specimens in the sample is known as the sample size. Sample test data is statistically analyzed, typically by computing the mean and the standard deviation. The sample mean and standard deviation then represent the mean and standard deviation of the parent population within specific confidence limits. They are ultimately used to determine the performance rating of the entire population.
16.5.2
Collapse Rating for Small Datasets
As an application of the direct method, it is sometimes convenient to increase the determinist collapse rating of a tube above the API minimum performance value. Usually, this adjustment is desired for a single or small group of wells, and the available dataset of collapse properties is small (typically less than 20). In such instances, application of formulas appearing in API TR 5C3 or ISO TR 10400 [9] can provide a statistically reasonable alternate collapse rating. The design collapse strength for a small dataset may be calculated from pdes0,95 = µs Fs σs ,
(16.2)
where
σs =
"
n X
# 12
2
(pc − µs ) / (n − 1)
i=1
,
(16.3)
n being the number of samples. The correction factor is given by2 [9], 2
3
F = 24.32720 − 57.45545log10n + 72.10244 (log10 n) − 52.72779 (log10 n) 4
5
6
7
+ 23.64113 (log10 n) − 6.41648 (log10 n) + 0.96953 (log10 n) − 0.06267 (log10 n) .
(16.4)
Table 16.1 summarizes a sample calculation for a dataset with n = 15. 2 The
formula for F given here should not be used for n ≤ 10. For n ≤ 10 see Table G.1 in Annex G of API TR 5C3 or ISO TR 10400.
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Table 16.1. Design Collapse Determination for a Small Dataset
16.5.3
Sample
pc
(pc − µs )2
1
5,557
2,389,497.64
2
6,551
304,483.24
3
5,539
2,445,470.44
4
8,692
2,525,556.64
5
7,799
484,694.44
6
8,349
1,553,014.44
7
6,612
240,884.64
8
6,213
791,744.04
9
7,953
722,840.04
10
9,355
5,072,404.84
11
6,909
37,558.44
12
5,657
2,090,337.64
13
6,967
18,441.64
14
5,743
1,849,056.04
15
8,646
2,381,466.24
Mean
7,102.80
Standard Deviation
1,279.16
Fs
3.8738
Design pc
2,147.6
Performance Properties by the Indirect Method
The right-hand portion of Figure 16.3 illustrates the indirect or synthesis method by which a tubular performance property may be specified. The tubular is described by the specified or minimum values of the different geometric and material properties. For example, 7 in. 23 ppf, L80 casing indicates that the pipe has a specified outside diameter of 7 in. a specified weight of 23 ppf and a minimum yield strength of 80 ksi. However, due to the nature of the manufacturing process and quality control procedures, each property is actually bounded within prescribed limits of manufacturing tolerance. Therefore, each property is described by maximum and minimum values and a statistical distribution as shown in Figure 16.3. The statistical distribution of the tubulars in a given batch or heat depends on the manufacturing procedures used at the mill. As an example, Figure 16.4 shows a histogram of wall thickness measured on 111 samples from a tubular EPT Drilling
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Mud density
Diameter
Reservoir pressure
Production fluid density
Resistance
p (load) p (resistance)
Load
Wall thickness
Yield stress
C
R
Kick volume
load resistance
PDFs of output variables (load resistance)
etc.
PDFs of input variables (load)
UTS
etc.
PDFs of input variables (resistance)
BPAD003_167.ai
Figure 16.3. Load and Performance specification
mill. Figure 16.5 shows the cumulative distribution for the same data. The wall thickness distribution varies between 0.263 in. (the minimum API wall thickness for this tube is 0.241 in.) and 0.301 in., and exhibits a peak in the neighborhood of its API specified value, 0.275 in. Also, the histogram indicates that the wall thickness is normally distributed implying that extreme values of the wall thickness are less likely to occur than values close to the specified value. Finally, Figure 16.6 shows the normal distribution superimposed on the wall thickness histogram. The normal distribution curve in Figure 16.6 is assumed to represent the distribution of the parent population from which the 111 samples were randomly chosen. Such histograms and distributions can be generated for all the properties of the tubular–outside diameter, wall thickness, ovality, yield and ultimate strength, etc.. The design rating of a tubular may then be determined by application of production quality statistics such as those illustrated in Figures 16.4–16.6 to a candidate predictive formula for the limit state in question. The formula will specify performance as a function of the geometrical properties (outside diameter, wall thickness, ovality, eccentricity, length) and the material properties (yield strength, ultimate strength, modulus of elasticity, Poisson’s ratio, shape of the material stress-strain curve, etc.) of a generic specimen, Limit State = f (Geometry, Material Properties).
(16.5)
Probabilistic design recognizes that the performance of the tubular is not represented by a single number, but rather by a distribution of values and accompanying probabilities of occurrence. This distribution arises due to the variation of the properties of the tubular (as discussed in the case of the wall thickness), see Figure 16.3. The various distributions of the input variables in Equation 16.5 are combined using statistical methods EPT Drilling
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Figure 16.4. Statistical Distribution of Wall Thickness, 5.500 in., 15.5 ppf, J55, Sample Size 111
Figure 16.5. Cumulative Distribution, 5.500 in., 15.5 ppf, J55, Sample Size 111
(such as the Monte Carlo method, First Order Reliability Method (FORM), etc.) to obtain the distribution of the limit state. The limit state equation is itself based on the physics of tubular behavior, while the statistical methods depend on the distributions of the relevant input variables. Depending on the wider application EPT Drilling
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Figure 16.6. Wall Thickness Distribution, 5.500 in., 15.5 ppf, J55, Sample Size 111
in view, the statistical limit state may then be compared to a (dterministic or probabilistic) load, or, with proper statistical analysis, the limit state distribution can be used to arrive at a design equation representing a suitable minimum upon which deterministic design may be based.
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Chapter 17
Connections 17.1
Introduction
Individual tube bodies are joined by threaded connections. These connections can range from simple, relatively inexpensive API designs available from a number of vendors to proprietary designs that may cost as much as the tube body. The ideal connection would be fully transparent. That is, it would allow the tubular string to behave as if it were one continuous cylinder in respect to both geometry and performance, but this is not physically possible. Therefore compromises have to be made between performance capabilities and increased radial dimensions over the pipe body. The degree to which the tube integrity is adversely affected is a major factor in the selection and cost of a connection. The sections to follow consider critical aspects of connection performance. The intent is to explain the variety of behavior that can be expected and to offer some insight into the disparity in costs between different connection designs. In this discussion, the datum will be the API Round Thread design, specifically as embodied in the LT&C connection. The API Round Thread form appears on API ST&C (casing), LT&C (casing), NUE (tubing) and EUE (tubing)1 . The design has a long history documenting both its strengths and weaknesses, but is still in wide use because of its low cost. The premise of the discussion will be, “Given the low cost and ready availability of API LT&C, what performance advantages are to be gained from a proprietary connection design that would justify the latter’s additional cost?”
17.2
Tensile Efficiency
Tensile efficiency for casing and tubing connections is defined as the ratio of a limit load of the connection to the corresponding limit load of the tube body. Historically, casing connection tensile efficiency has been defined as the ratio of the parting load (either fracture or junpout) of the connection to the parting load of the tube body. On the other hand, tubing connections, which may be repeatedly disassembled and assembled, 1 The
abbreviations stand, respectively, for Short Thread and Coupling, Long Thread and Coupling, Non-Upset End and External Upset End.
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use yield as a limit load. Within BP, both casing and tubing are rated using yield as the limit load. Therefore, the tensile efficiency for both casing and tubing is defined as the ratio of the yield load of the connection to the yield load of the tube body. Most proprietary connection ratings for joint strength recognize the existence of a weak point or critical section area at one location in the connection, so that tensile efficiency is just the ratio of the connection critical cross section to the cross-sectional area of the pipe body. One difficulty with applying the above definition of tensile efficiency has to do with connections that do not yield or fail according to the formula “limit load x critical area”. The most notable examples are API Round Thread connections which may fail due to junpout. In such instances, yield of the connection is defined by lowering the alternate failure load by the ratio fymn /fumn .
17.2.1
Upsets
For thread designs that do not involve thread profiles that traverse the entire wall thickness of the tube, one means of increasing tensile efficiency is to increase the thickness of the tube body in the vicinity of the connection (see Figure 17.1). The thread form is then cut on a “thicker tube”, resulting in a high efficiency (since efficiency is relative to the pipe body). Two disadvantages to the implementation of upsets are: • The upsetting process involves severe hot forging of the end of the tube that must be followed by full tube body heat treatment. Although seldom a problem in modern upsetting facilities, the possibility of undesirable stresses and associated ring worm corrosion following upsetting does exist. • Upsetting limits the number of times a thread design can be recut on a tube without having to re-upset the tube end.
17.2.2
Low and Negative Angle Load Flanks
API Round Thread LT&C and ST&C connections have a 30◦ load (and stab) flank which promotes a pernicious failure mode known as junpout. In junpout neither the thread profile (due to shear) nor the connection body (due to fracture) fails. Rather, inelastic deformation of the connection results in a radial displacement of the pin from the box which, when it reaches the magnitude of the thread height, causes separation of the connection components. Although normally associated with the API Round Thread profile, junpout is not limited to this thread design. If the diameter:thickness ratio of the pipe is large enough, junpout can even occur in API Buttress whose load flank is 10◦ . As illustrated in Figure 17.2, the contact stresses between pin and box threads in the Round Thread profile can be decomposed into an axial component, the portion of the contact force/stress that carries axial load, and a radial component2 . The latter force displaces the pin away from the box and, given sufficient displacement, results in radial separation of the connection components. 2 In
viewing the figure, the right-hand drawing is a simplification of the more accurate left-hand drawing. In the right-hand drawing, friction at the load flank interface is ignored, retaining the essence of the argument in a somewhat easier to understand picture.
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12345654789 4 94
Figure 17.1. Example of T&C Connection Designed on Upset - Hunting TKC
Figure 17.2. Thread Flank Forces on API Round Thread
To minimize junpout, most proprietary threads lower the angle of the load flank3 of the thread. The 3 The
load flank of a thread is that flank exposed to the highest contact stresses when the connection is loaded in tension. The stab flank of a thread is that flank most likely to be damaged during the stabbing operation when the connection is being
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Figure 17.3. Example of Integral Connection with Negative Load Flank Angle Tenaris-Hydril SLX
amount of this alteration can vary from threads which copy the API Buttress thread form (3◦ load flank) to threads that actually go beyond 0◦ and possess a negative load flank angle (Figure 17.34 ). This latter design is particularly prevalent in clearance connections where the overall thickness of the connection dictates that the threads must withstand the maximum load possible. The above statements, of course, pertain primarily to tensile loading. Often the stab flank of a thread has quite a high angle (on the order of 45◦ in some offerings) to benefit stabbing the pin into the box on assembly. This high stab flank angle is conventionally counteracted by a shoulder at some point in the connection intended to carry the compressional loading (Figure 17.4). As an alternative to such a shoulder, some vendors actually cut both flanks of the thread with negative angles (Figure 17.5).
assembled. 4 Unless
stated otherwise, all connection pictures in this chapter are from World Oils Casing and Tubing Tables, www.WorldOil.com, with permission.
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Figure 17.4. Example of T&C Connection with Negative Load Flank Angle and Reverse Torque Shoulder - VAM TOP
17.3
Leak Resistance
The Round Thread design has two inherent spiral leak paths, one following the thread root and one following the thread crest5 . The intended purpose of thread lubricant is to block these paths when small, ductile metal R or Teflon particles in the lubricant grease carrier deform during assembly. This concept is flawed by the following possibilities: • There is no guarantee that the solid particles in the lubricant will bridge at any point in either of the potential leak paths. That bridging does not always occur is evident from the number of leaks in older wells, where the grease carrier is no longer present. • The grease carrier has temperature limitations. At atmospheric pressure, the grease carrier commonly used in API Modified thread compound will vaporize at approximately 138◦ C (280◦ F) • The grease carrier is typically a petroleum-based product and can be leeched away by contact with wellbore hydrocarbon fluids. 5 An
additional leak path can be created on the stab flanks of the round thread profile, given a suitable combination of pressure and tension. This leak path, however, is not mitigated by thread lubricant.
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Figure 17.5. Example of Integral Connection with Negative Load and Stab Flank Angle - Tenaris-Hydril 521
• Heavy metal particles used to promote bridging in many conventional lubricants pose environmental and health hazards. In recent years this issue has been addressed by the replacement of soft metals R However, the experience of the industry with more environmentally friendly materials such as Teflon . with these newer compounds is short, and their long term sealing behavior is undefined.
• Inter-thread movement during assembly and subsequent application loads, particularly hanging tension, can redistribute both thread lubricant and the contact loads on the thread flanks. This problem is critical in API Buttress connections, where the clearances are potentially greater and the shape of the thread profile enhances redistribution of the lubricant. To combat these problems, the common solution is to ensure that at least one location in the inter-thread area contains a positive barrier to prevent fluid escape. The nature of this barrier can assume different forms.
17.3.1
R Teflon Ring
Both the API and proprietary vendors offer designs modified by a groove generally within the coupling or R R box threads in which a Teflon ring is inserted. BP does not consider Teflon rings to be an appropriate solution for the following reasons: EPT Drilling
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• Correct installation of the ring is critical, offering the possibility of error in assembly. • The tolerance on ring dimensions vis-a-vis the dimensions of the groove, particularly for the API ring design, admits the possibility of either inducing unnecessary stresses with an over-sized ring or failing to achieve a seal with an under-sized ring. R • Teflon ring has a coefficient of thermal expansion approximately ten times that of steel, offering the
possibility of unnecessarily stressing a connection in a high temperature environment. R • Above a temperature of roughly 120◦ C (250◦ F), Teflon loses its memory and will not return to its
previous configuration during cooling. Despite these limitations, and particularly in instances where a pressure seal is critical but the temperature R and pressure are not extreme, Teflon represents a possible alternative to thread lubricant as a primary seal.
17.3.2
Metal-to-metal Seals
The most popular and most satisfactory seal in a threaded connection is to include a segment of the interthread region, usually at the end of the pin, where positive interference between metal surfaces exists for the entire circumference of the connection (Figure 17.6). The intricacies of metal-to-metal seal design are beyond the scope of this discussion. However, certain basic principles should be followed in evaluating a metal-to-metal sealed connection: • Radial seals, that is, sealing surface where the direction of contact stress is radial, are preferred over axial seals. A torque shoulder, used to limit the relative axial displacement of the pin and box during assembly, is not to be considered a seal. Such surfaces usually lose some or all of their contact stress when loaded axially. • The contour of the seal surface(s) varies with vendor. For example, by giving one or both of the seal surfaces a convex contour, a limited seal region of very high stress and, therefore, very high sealing potential can be created. Such a design, however, can in the extreme lead to a connection prone to gall. Compromise contours include one seal surface convex with the other straight (e.g., a cone seal surface) and both seal surfaces straight. • The wall thickness of the pin seal is usually designed to promote the self-energizing effect. Selfenergizing occurs when the internal pressure attempting to cause the leak also forces the end of the pin into its mating box or coupling surface, thus increasing seal contact pressure. Unfortunately, and particularly for higher wall thickness products, a thin, flexible pin seal can result in a non-flush inside diameter profile. Such a profile is not suitable for high well flow rates (refer to Paragraph 14.5.1)
17.3.3
BP Classes
Each connection in the list of approved BP connections is placed in a class based on its rated leak resistance. The classes are then matched to differential pressure environments as indicated in Table 17.1. The BP Class designations are based strictly on differential pressure and do not contain allowance for either tensile efficiency or behavior under combined loading (for example, internal pressure and compression). EPT Drilling
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Figure 17.6. Example of T&C Connection with Metal-to-Metal Seal and Torque Shoulder - VAM TOP
Table 17.1. BP Connection Classes Differential Working Pressure (Internal to External)
BP Class
> 103 MPa
> 15,000 psi
4
69 to 103 MPa
10,000 to 15,000 psi
3
35 to 69 MPa
5,000 to 10,000 psi
2
< 35 MPa
< 5,000 psi
1
The class rating is an evaluation of the performance of a connection with respect to pressure integrity and assumes the connection will be designed in tension for the intended application. For example, the VAM SLIJ-II design is a Class 4 connection. The tensile efficiency of SLIJ II, however, averages roughly 75%. SLIJ II is a clearance connection, typically used for production liners and tiebacks and, in these applications, is not expected to attain 100% tension efficiency. The connection is, however, expected to reliably hold high pressures, such as those associated with a tubing leak, throughout the life of the completion. Other aspects of the Class designations include: • All classes except Class 4 have associated with them a test sequence which the connection must pass EPT Drilling
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to attain a given rating. It is well known, however, that laboratory test conditions cannot always duplicate the severity of in situ loading. A Class 4 connection is a connection that has passed the test sequence for Class 3 and, in addition, has proven itself a reliable design via substantial field experience. • A Class 3 connection shall have a metal to metal seal. • Class 2 connections may have a radial metal-to-metal seal or thread seal, but that seal may not be judged to be as reliable, particularly in tension, as seals reaching Class 3. • Connections that depend only on thread lubricant for a seal are normally Class 1 • Pressure ratings in the Class table assume long-term exposure. For example, a Class 1 connection, such as API LT&C, can hold substantial pressure for the duration of a typical rig site pressure test. The Class designations, on the other hand, address the whole life of the connection.
17.4
Internal Stresses
A recognized shortcoming of the API Round Thread and Buttress designs is that the only aspect of the design opposing excess assembly turns is the thread taper. Depending on the relative wall thicknesses in the pin and box, excess assembly can result in yielding at the end of the pin or, conversely, excess hoop stress in the box. This latter situation is of particular concern in sour service applications where the middle of the box is exposed to wellbore fluids. Excess interference between the pin and box members can also serve as a site for galling. Limiting pin/box interface stresses, therefore, is an important aspect of connection design especially for 13 Chrome and other CRA materials, where Round Thread or Buttress should not be considered for use. Limiting assembly turns can also assume importance in high torque applications. Liner drilling, particularly in assemblies where the casing is rotated as part of the drill string, and rotation during cementing in medium to high curvature build sections can result in downhole make-up for connections low in torsional resistance. To combat the possibility of excess assembly stresses, two solutions are typically applied.
17.4.1
Cylindrical Threads
Designing a thread with zero taper will, of course, eliminate stresses associated with a tapered thread geometry (Figure 17.7). Cylindrical threads are typically free running with little or no radial thread interference, and therefore tend to be more gall resistant. Cylindrical thread designs typically possess a torque shoulder. The preload and friction force associated with this shoulder is usually sufficient to prevent connection rotation in the wellbore.
17.4.2
Torque Shoulder
A number of thread designs have a thread on a taper, but limit the amount of interference between the pin and box by means of a positive stop, termed a torque shoulder. The torque shoulder must not be mistaken for EPT Drilling
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Figure 17.7. Example of Integral Connection with Cylindrical Thread Profile Benoit BTS-6
a metal-to-metal pressure seal; the torque shoulder is an effective solution to the problem of excess assembly stress (Figure 17.8).
17.5
Internal Profile
In applications involving high flow rates, for example in high volume gas wells, the internal profile at the interface between tube and connection should be as smooth as possible. Most proprietary connection designs attempt to maintain a smooth transition in the bore. It should be emphasized, however, that for very high flow rates, even a small change in flow diameter can induce turbulence resulting in erosive wear followed by the possibility of corrosion.
17.6
Multidimensional Loading
For a connection to be truly transparent, it should equal the performance properties of the tube body for all load combinations. For tensile loading, this is an accurate description of most threaded and coupled proprietary threads. For axial compression, and in some cases for external pressure, most connections fall short of matching the resistance of the tube body. With the current emphasis on combination of loads, performance envelopes for connections are increasEPT Drilling
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Figure 17.8. Example of T&C Connection with Torque Shoulder - VAM TOP
Figure 17.9. Example of Integral Connection Performance Ellipse - Vam SLIJ II
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ingly available from their respective vendors. As an example, Figure 17.96 is the performance envelope for Vam SLIJ II. The four quadrants represent: 1. Internal pressure and tension. The upper right portion of the figure typically governs load scenarios such as long-term shut-in (wellbore heat-up dissipated) and its effect near the surface (production casing or tieback) or tubing hanger. 2. Internal pressure and compression. A typical load scenario is high temperature production, particularly near the bottom of the string where compression is greatest. 3. External pressure and compression. This load case can be particularly important late in the life of a tubing or casing string when the hydrostatic pressure exerted by the annular fluid may exceed the internal pressure due to production. A trapped tubing/casing annulus can also lead to load scenarios with application in this quadrant. 4. External pressure and tension. A potential load scenario here would be production after a long-term shut-in, where the shut-in tubing/casing or casing/casing annulus builds pressure due to a leak. This load case is particularly important at the surface or tubing hanger where tension can significantly reduce external pressure resistance. In viewing Figure 17.9, three curves are evident. The outer, blue ellipse represents initial yield at the inner radius of the tube (refer to Chapter 11, Triaxial Design Analysis). The envelope is actually two halfellipses. The upper ellipse strictly applies to load cases with zero external pressure. The lower ellipse strictly applies to load cases with zero internal pressure. This is the preferred method of representing initial yield of the tube body in API RP 5C5 or ISO 13679 [8]. The portion of the tube body ellipse in the fourth quadrant often represents the API minimum collapse resistance of the tube (refer to Chapter 8, Collapse Design Criteria). According to the diameter:thickness ratio, yield strength and applied tension, this curve may be inside or outside the yield ellipse. The curve representing lower resistance to external pressure governs. The second, green curve in the figure is the performance envelope for the connection. As indicated, for tension the SLIJ II connection is not as strong as the tube body. SLIJ II is a swaged, integral connection, and should not be expected to have a tensile efficiency of 100%. For compression, the connection can withstand an axial load equal to approximately 70% of tube body yield before loss of integrity. Typically, “loss of integrity” in compression implies leak and not structural failure of the connection7 . In connections designed without consideration for compression, however, loss of integrity may imply destruction of the connection as an axial load bearing member. 6 Picture 7 Loss
used with permission of Vam North America.
of leak integrity in compression is often related to yield of an internal connection component, such as a torque shoulder.
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17.7
Families of Connections
Given the variety of considerations discussed in previous sections, vendors have combined some, all, or none of these features to produce a multitude of designs. Fortunately, these designs fall into a small set of families. General characteristics (advantages and disadvantages) of casing/tubing connections families are described below. “Family” as discussed below does not necessarily determine “category”.
17.7.1
API 8 Round (ST&C, LT&C, EUE and NUE)
• Good availability and price • Liquid sealability up to about 210◦F • Poor gas tightness • Gauges and expertise are widely available for rework and refurbishment • Prone to galling and cross-threading due to out of roundness, especially in larger ODs • High assembly circumferential (hoop) stress in coupling • Can junpout at a variety of wall thicknesses for medium and larger diameters • Tensile efficiency (ST&C, LT&C, NUE) = 70 to 75% depending on thread type • Tensile efficiency (EUE) = 115 to 120%
17.7.2
API Buttress
• Good availability and price • Liquid sealability up to about 210◦F • Poor gas tightness • Tin plating improves leak resistance8 • Gauges and expertise are widely available for rework and refurbishment • Prone to galling and to cross-threading due to out of roundness, especially in larger ODs • High assembly circumferential (hoop) stress in coupling • Can junpout at a variety of wall thicknesses for larger diameters • Tensile efficiency is generally 85 to 95% of pipe body 8 Although
this is a legitimate improvement, and one practiced by at least one major operator, tin plating is not recommended as a solution for leak integrity in BP designs.
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17.7.3
Metal-to-Metal Seal, Threaded and Coupled
• Availability to depend on proprietary type, e.g., VAM, Hunting, Tenaris-Hydril etc. • Good gas tightness, generally • Special clearance couplings manufactured from same or higher grade material are available to improve hole clearance9 • Susceptible to handling damage if not treated with care • Pins must be bored concentric to seals for effective gas sealing • Particularly suited to use on cold worked high alloys that cannot be upset or swaged • Generally good make-up characteristics due to reduced thread interference compared to API connections • Gauges and expertise are available, depending on type, for rework and refurbishment and can readily be recut • Assembly circumferential (hoop) stress in coupling can be controlled by reduced thread interference since sealing in the thread is not a requirement • Tensile efficiency is generally at least equal to Buttress and in most instances is equal to or exceeds pipe body
17.7.4
Metal-to-Metal Seal, Upset and Integral (or Coupled)
• Mostly riser connections or test strings • Poor availability of couplings and limited upset recuts for pipe refurbishment • Costly, especially upsetting • Good gas tightness • Usually exhibiting very good repeated make/break capabilities • Susceptible to handling damage if not treated with care • Pins must be bored concentric to seals for effective gas sealing • Tensile efficiency at least equal to or greater than pipe body 9 Because
of the lack of test data on special clearance connections, they are not recommended as a solution for improving hole clearance in BP designs.
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17.7.5
Metal-to-metal Seal, Formed and Integral (Semi-flush and Flush)
• Hole clearance characteristics excellent • Reasonable availability, easy to refurbish/recut, no requirement for couplings, swaging equipment required for swaged type connections • Good gas tightness • Pins must be bored concentric to seals for effective gas sealing • Tensile efficiency usually 50 to 80% of pipe body depending on type of connection (some flush connection can have a tensile efficiency less than 50%, depending on size) • Connections not having a metal-to-metal seal may be weaker than the pipe body for internal pressure rating • Susceptible to handling damage if not treated with some care
17.7.6
Weld On
• Costly (connector, weld and NDT) • Elimination of mill end with weld on box10 • Coarse threads to resist cross threading or galling • Continuous threaded product resists disengagement under severe bending • Grades limited to weldable (line pipe) or Grade H40, K/J-55 • Tensile efficiency generally greater than pipe body
17.8
Approved Connection List
The connections in Tables 17.2-17.7 have been approved by EPT for use by BP. All connections on the list have adequate design characteristics to meet their intended area of service. Connection designs not appearing on the list are not necessarily flawed. In some instances, the number of choices in a category were limited simply to restrict the inventory of weight/grade/thread combinations which the Company will stock. This list is updated periodically; the latest version will always appear on the Tubular Technology web site (http://octgdesign.bpweb.bp.com/). 10 This
is strictly true only for the XLW connection by XL Systems. In most cases both the pin and box are welded on.
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Table 17.2. Large OD Connections for Casing (Non-Rotating, Weight Set) Connection
Size
Primary Mfr
BP
Status
Application
Commentsb
Classa
Range ALT-2
20.00042.000
Vetco-Gray
1
Approvedc
Cond/Surf
Threadless, weight set, driveable, heavy duty connector. Requires mechanical release. Typically reusable.
ST-2
30.000
Vetco-Gray
1
Approvedc
Cond/Surf
Smaller version of ALT-2 for thinner wall pipe. Same characteristics.
QUIK-STAB
20.00036.000
Dril-Quip
1
Approvedc
Cond/Surf
Threadless, weight set, driveable, heavy duty connector. Requires mechanical release. Typically reusable. Several versions, see manufacturer’s catalog.
QUIK-JAY
30.00036.000
Dril-Quip
1
Approvedc
Cond/Surf
Threadless, weight set, driveable connector. Release w/key and 1/16 turn. Typically reusable.
LYNX
20.00036.000
Oil States
1
Approvedc
Cond/Surf
Threadless, weight set, driveable, 3-piece connector. Requires jacking bolts for release. Typically reusable, SA, HT and HD versions.
MERLIN
20.000-
Oil States
1
Approvedc
Cond/Surf/Riser
36.000
Grooved, uses hydraulic clamp and pressure injector to assemble, requires same equipment for release. Good fatigue properties. S, D, HT and TLE versions. Other sizes available.
a See Table 17.1. b Tensile (Joint) Efficiency (TE) ratings are based on parting load and seal maintenance. Compression Efficiency (CE) ratings are based on seal failure, not necessarily mechanical failure. c Application on material with higher than 80 ksi minimum yield strength needs a full evaluation.
Table 17.3. Large OD Connections for Casing (Threaded) Status
Application
Commentsb
2
Approved
Cond/Surf
Flush ID and OD, tapered dovetail threads, high yield torque, radial metal-to-metal seal. Economical connection for drive, conductor and surface applications. 5565%TE/CE.
Grant Prideco
2
Approved
Cond/Surf
XLF with a flush OD and a reduced ID bore for increased axial strength. Pin and box are machined from thick pipe and welded-on. 100%TE/CE.
Grant Prideco
2
Approved
Cond/Surf/Riser
Connection
Size Range
Primary Mfr
XLF
20.00048.000
Grant Prideco
XLF-RB
20.00048.000
XLCS
20.000-
BP Classa
48.000
XLF with increased thread root radii for better fatigue life and an external environmental seal. Excellent fatigue properties. 55-65%TE/CE.
XLCS-RB
20.00048.000
Grant Prideco
2
Approved
Cond/Surf/Riser
XLC-S with a flush OD and a reduced ID bore for increased axial strength. Pin and box are machined from thick pipe and welded-on. 100%TE/CE.
XLW
20.00048.000
Grant Prideco
2
Approvedc
Cond/Surf
Tapered dovetail threads, high yield torque, radial metal-to-metal seal. The box has an elevator shoulder, is machined on a forging and welded to the pipe, the pin is machined directly on the pipe. 100%TE/CE.
RL-4
20.00036.000
Vetco-Gray
1
Approvedc
Cond/Surf
Threaded 1/4 turn make-up and release. Driveable and typically reusable. Lock tabs strongly recommended. RL4S and several other versions available, see manufacturer’s catalog.
RL-1
20.00036.000
Vetco-Gray
1
Approvedc
Cond/Surf
1-2 turn make-up version of RL-4.
QUIKTHREAD
20.00036.000
Dril-Quip
1
Approvedc
Cond/Surf
Threaded 2.5 turn make-up and release. Driveable and typically reusable. Several versions, see manufacturer’s catalog.
MULTI-
20.000-
Dril-Quip
1
Approvedc
Cond/Surf
THREAD
36.000
LEOPARD SD
20.00036.000
Oil States
1
Approvedc
Cond/Surf
Threaded one turn makeup and release. Driveable and typically reusable.
SWIFT DW2
20.00036.000
Oil States
1
Approvedc
Cond/Surf
Similar to Leopard with a radial metal to metal seal.
20.000-
Grant Prideco
1
Provisionald
Cond/Surf
Threaded 2-3 turn make-up and release. Driveable and typically reusable.
VIPER
Threaded 5/8 turn make-up and release version of Quik-Thread. Lock tabs strongly recommended.
36.000 a See Table 17.1. b Tensile (Joint) Efficiency (TE) ratings are based on parting load and seal maintenance. Compression Efficiency (CE) ratings are based on seal failure, not necessarily mechanical failure. c Application on material with higher than 80 ksi minimum yield strength needs a full evaluation. d Provisional means the connection has been tested and appears to be technically satisfactory, but needs field evaluation prior to final approval. Please contact EPT Drilling prior to using any Provisional connection.
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Table 17.4. Threaded and Coupled Connections for Tubing and Casing Status
Application
Commentsb
4
Approved
Int/Prod Mc
Hooked threads, trapped ID torque shoulder, radial metal-to-metal seal. 100%TE/3572%CE.
Tenaris-Hydril
4
Approved
Int/Prod Hc
Tapered dove tail threads, high yield torque, radial metal-to-metal seal. Excellent connection for bending, rotating and high torque. 100%TE/CE.
V&M/SMI
4
Approved
Int/Prod Mc
Hooked
Connection
Size Range
Primary Mfr
SEAL LOCK HC
4.50014.000
Hunting
563
2.37516.000
VAM TOP
2.375-
BP Classa
14.000
threads,
trapped
ID
torque
shoulder,
radial metal-to-metal seal.
100%TE/60%CE (CE 100% sizes 2.375-4.500.)
VAM KP
TOP
5.0007.625
V&M/SMI
4
Approved
Int/Prod Mc
KP version for BP sizes 5”-7.625”, completely interchangeable with VAM TOP. 100%TE/60%CE.
VAM HT
TOP
5.0007.000
V&M/SMI
4
Approved
Int/Prod Mc
VAM TOP for high torque applications. 100%TE/80%CE.
VAM HC
TOP
5.0007.750
V&M/SMI
4
Approved
Int/Prod Mc
VAM TOP for high compression applications. 100%TE/100%CE.
2.375-
JFE
3
Provisionald
Int/Prod Lc
Positive angle load flank thread, trapped ID torque shoulder, radial metal-to-metal
Bear
9.625
seal. 100%TE/100%CE.
TC-II
5.00013.375
Grant Prideco
3
Provisionald
Int/Prod Lc
Positive angle load flank thread, trapped ID torque shoulder, radial metal-to-metal seal. 100%TE/100%CE.
Blue
2.37513.625
Tenaris-Hydril
3
Provisionald
Int/Prod Mc
Positive angle load flank thread, trapped ID torque shoulder, radial metal-to-metal seal. 100%TE/100%CE.
5.00014.000
V&M/SMI
3
Approved
Int/Prod Mc
Hooked threads, trapped ID torque shoulder, radial metal-to-metal seal. For thick wall pipe where VAM TOP does not work. 100%TE40%CE.
2.375-
Tenaris-Hydril
2
Approved
Int/Prod Hc
Tapered dove tail threads, high yield torque, thread seal. Excellent connection for
VAM ST
HW
561
4.500
bending, rotating and high torque. 100%TE/CE.
BOSS
7.62520.000
Hunting
2
Approved
Surf/Int/Prod Lc
Hooked threads, pin-to-pin torque shoulder, thread seal. 100%TE/45-73%CE.
SEAL LOCK HT
2.0637.000
Hunting
2
Approved
Int/Prod Lc
BOSS on smaller OD sizes. 100%TE/50-84%CE.
DINO VAM
9.62516.000
V&M/SMI
2
Approved
Surf/Int/Prod Lc
Hooked threads, pin-to-pin torque shoulder, thread seal. 100%TE/50%CE.
ATS-E
7.000-
Grant Prideco
2
Provisionald
Surf/Int/Prod Lc
Hooked threads, pin-to-pin torque shoulder, thread seal. 100%TE/50%CE.
20.000 GP-3P
16.00020.000
Tenaris-Hydril
2
Approved
Surf/Int/Prod Lc
Positive angle load flank thread, zero degree torque shoulder, thread seal. 100%TE/83-100%CE
BUTTRESS
4.50013.375
API
1
Approvede
Surf/Int/Prod Lc
API buttress thread, no torque shoulder, no seal. Available up to 20.000, but not recommended above 13.375. Will not contain pressure long term, is typically difficult to make up and is usually not reusable. 85-95%TE.
LT&C
4.5009.625
API
1
Approvede
Int/Prod Lc
API 8 Round thread, no torque shoulder, no seal. Will not contain pressure long term. Easier to make up than buttress, but still usually not reusable. 75-95%TE.
EUE 8R
2.0634.500
API
1
Approvede
Prod Lc
API 8 Round thread machined on external upset pipe, no torque shoulder, no seal. Will not contain pressure. 100%TE.
a See Table 17.1. b Tensile (Joint) Efficiency (TE) ratings are based on parting load and seal maintenance. Compression Efficiency (CE) ratings are based on seal failure, not necessarily mechanical failure. c Directional hole application recommendation based on dogleg severity: L (Low): 0◦ -10◦ /100 ft for sizes ≤ 9-7/8, 0◦ -5◦ /100 ft for sizes > 9-7/8 Most connections. M (Medium): 10◦ -20◦ /100 ft for sizes ≤ 9-7/8, 5◦ -15◦ /100 ft for sizes > 9-7/8 Connections with hooked threads and a trapped torque shoulder. H (High): ¿20◦ /100 ft for sizes ≤ 9-7/8, > 15◦ /100 ft for sizes > 9-7/8 Connections with a tapered dovetail thread. d Provisional means the connection has been tested and appears to be technically satisfactory, but needs field evaluation prior to final approval. Please contact EPT Drilling prior to using any Provisional connection. e Application on material with higher than 80 ksi minimum yield strength needs a full evaluation.
17.9
Connection Selection Decision Tree
Figures 17.10 and 17.11 present a decision tree to aid in selecting the most appropriate connection, or group of similar connections, for an application. Construction of the decision tree took account of the following aspects of connection performance: EPT Drilling
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Table 17.5. Integral Connections for Casing (Expanded/Swaged or Semi-Flush Type) Connection
Size
Primary Mfr
BP
Status
Application
Commentsb
Classa
Range SLIJ-II
5.00013.625
V&M/SMI
4
Approved
Liner/TB Lc
Two-step, hooked threads, 90◦ step torque shoulder, radial metal-to-metal ID seal. 70-80%TE/70%CE.
SLSF
4.500-
Hunting
4
Approved
Liner/TB Lc
Hooked threads, trapped OD torque shoulder, radial metal-to-metal ID and OD seals.
14.000
73-76%TE/47-52%CE.
Advanced NJO
4.50013.625
Grant Prideco
4
Approved
Liner/TB Mc
Two-step hooked threads, trapped step torque shoulder, radial metal-to-metal ID seal. 68-80%TE/35-65%CE.
SLX
4.50013.625
Tenaris-Hydril
4
Approved
Liner/TB Mc
Two-step hooked threads, trapped step torque shoulder, radial metal-to-metal ID seal. 68-80%TE/36-41%CE.
MAC II
5.50016.000
Tenaris-Hydril
4
Approved
Liner/TB Mc
Two-step hooked threads, trapped step torque shoulder, radial metal-to-metal ID seal. 66-82%TE/33-40%CE. Basically SLX for thick wall pipe.
523
7.000-
Tenaris-Hydril
3
Approved
Liner/TB Hc
Tapered dovetail threads, high yield torque, metal-to-metal ID seal. Excellent con-
16.000
521
4.000-
nection for bending, rotating and high torque. Machined on a 3-5% box expansion, 71-76%TE/80-84%CE. Tenaris-Hydril
2
Approved
Liner/TB Hc
18.625
Tapered dovetail threads, high yield torque, thread seal.
Excellent connection
for bending, rotating and high torque. Machined on a 3-5% box expansion, 6177%TE/74-89%CE.
a See Table 17.1. b Tensile (Joint) Efficiency (TE) ratings are based on parting load and seal maintenance. Compression Efficiency (CE) ratings are based on seal failure, not necessarily mechanical failure. c Directional hole application recommendation based on dogleg severity: L (Low): 0◦ -10◦ /100 ft for sizes ≤ 9-7/8, 0◦ -5◦ /100 ft for sizes > 9-7/8 Most connections. M (Medium): 10◦ -20◦ /100 ft for sizes ≤ 9-7/8, 5◦ -15◦ /100 ft for sizes > 9-7/8 Connections with hooked threads and a trapped torque shoulder. H (High): ¿20◦ /100 ft for sizes ≤ 9-7/8, > 15◦ /100 ft for sizes > 9-7/8 Connections with a tapered dovetail thread. d Provisional means the connection has been tested and appears to be technically satisfactory, but needs field evaluation prior to final approval. Please contact EPT Drilling prior to using any Provisional connection.
Table 17.6. Integral Connections for Tubing and Casing (Flush) Connection
Size
Primary Mfr
BP
Status
Application
Commentsb
Classa
Range FJL
2.3757.625
V&M/SMI
3
Approvedc
Liner Ld
Hooked threads, trapped OD torque shoulder, radial metal-to-metal ID seal. 5065%TE/40%CE.
SLF
2.875-
Hunting
3
Approvedc
Liner Ld
Hooked threads, trapped OD torque shoulder, radial metal-to-metal ID seal. 48-
7.625
65%TE/27-48%CE.
STL
2.3757.625
Grant Prideco
3
Approvedc
Liner Ld
Hooked threads, trapped OD torque shoulder, radial metal-to-metal ID seal. Twostart thread form. 44-65%TE/CE=0.6TE
513
4.50016.000
Tenaris-Hydril
3
Approved
Liner Hd
Tapered dovetail threads, high yield torque, metal-to-metal ID seal. Excellent connection for bending, rotating and high torque. Machined on non upset pipe. 5966%TE/70-79%CE.
511
2.06311.875
Tenaris-Hydril
2
Approved
Liner Hd
Tapered dovetail threads, high yield torque, thread seal. Excellent connection for bending, rotating and high torque. Machined on non upset pipe. 55-65%TE/6881%CE.
16.00018.625 a See Table 17.1. b Tensile (Joint) Efficiency (TE) ratings are based on parting load and seal maintenance. Compression Efficiency (CE) ratings are based on seal failure, not necessarily mechanical failure. c VAM FJL, Hunting SLF, and Grant Prideco STL are only recommended for sizes 2.375-7.625 and applications of 4000 ft. (1200 m) or less in length. d Directional hole application recommendation based on dogleg severity: L (Low): 0◦ -10◦ /100 ft for sizes ≤ 9-7/8, 0◦ -5◦ /100 ft for sizes > 9-7/8 Most connections. M (Medium): 10◦ -20◦ /100 ft for sizes ≤ 9-7/8, 5◦ -15◦ /100 ft for sizes > 9-7/8 Connections with hooked threads and a trapped torque shoulder. H (High): ¿20◦ /100 ft for sizes ≤ 9-7/8, > 15◦ /100 ft for sizes > 9-7/8 Connections with a tapered dovetail thread.
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Table 17.7. Integral Connections for Tubing and Casing (Upset) Status
Application
Commentsb
4
Approvedc
Prod/Work/Test Ld
Two-step thread, trapped OD torque shoulder, radial metal-to-metal seal. Backup 90◦ torque shoulder on step. Available with CB ring for internal coating applications. Not recommended for high rate 13Cr material applications. 100%TE/100%CE.
Tenaris-Hydril Benoit/Hunting/ Grant Prideco
4
Approvede
Prod Ld
Thin wall version of 2-Step/4 or 6 Pitch. 100%J/80%CE.
2.3754.500
Tenaris-Hydril
3
Approved
Prod Hd
Tapered dovetail threads, high yield torque, metal-to-metal ID seal. Excellent connection for bending, rotating and high torque. Machined on an API EUE upset.
533
2.3757.625
Tenaris-Hydril
3
Approved
Prod Hd
Tapered dovetail threads, high yield torque, metal-to-metal ID seal. Excellent connection for bending, rotating and high torque. Machined on a two-step upset. Available
553
2.3757.625
Tenaris-Hydril
3
Approved
Prod Hd
Tapered dovetail threads, high yield torque, metal-to-metal ID seal. Excellent connection for bending, rotating and high torque. Machined on API OUE pipe. 88-
501
2.3754.500
Tenaris-Hydril
2
Approved
Prod Hd
Tapered dovetail threads, high yield torque, thread seal. Excellent connection for bending, rotating and high torque. Machined on an API EUE upset. 100%TE/CE.
531
2.3754.500
Tenaris-Hydril
2
Approved
Prod Hd
Tapered dovetail threads, high yield torque, thread seal. Excellent connection for bending, rotating and high torque. Machined on a two-step upset. Available with CB ring for internal coating applications. 100%TE/CE
551
2.3754.500
Tenaris-Hydril
2
Approved
Prod Hd
Tapered dovetail threads, high yield torque, thread seal. Excellent connection for bending, rotating and high torque. Machined on API OUE pipe. 88-92%TE/100%CE.
Connection
Size Range
Primary Mfr
2-Step, 4 or 6 Pitch
2.0634.500
Tenaris-Hydril Benoit/Hunting/ Grant Prideco
2-Step, Pitch
2.0637.000
503
8
BP Classa
100%TE/CE.
with CB ring for internal coating applications. 100%TE/CE.
92%TE/100%CE.
a See Table 17.1. b Tensile (Joint) Efficiency (TE) ratings are based on parting load and seal maintenance. Compression Efficiency (CE) ratings are based on seal failure, not necessarily mechanical failure. c Tenaris-Hydril PH6/PH6-CB, Benoit BTS-6/BTS-6PR, HI TS-HD/TS-HD-SR, and GP RTS-6/RTS-6PR are equivalent connections. The Benoit, Hunting, and Grant Prideco connections are interchangeable with the Tenaris-Hydril connection, but NOT with each other. Tenaris-Hydril no longer markets 2-Step connections, they will continue to support existing material. d Directional hole application recommendation based on dogleg severity: L (Low): 0◦ -10◦ /100 ft for sizes ≤ 9-7/8, 0◦ -5◦ /100 ft for sizes > 9-7/8 Most connections. M (Medium): 10◦ -20◦ /100 ft for sizes ≤ 9-7/8, 5◦ -15◦ /100 ft for sizes > 9-7/8 Connections with hooked threads and a trapped torque shoulder. H (High): ¿20◦ /100 ft for sizes ≤ 9-7/8, > 15◦ /100 ft for sizes > 9-7/8 Connections with a tapered dovetail thread. e Tenaris-Hydril CS/CS-CB, Benoit BTS-8/BTS-8PR, HI TS-HP/TS-HP-SR, and GP RTS-8/RTS-8PR are equivalent connections. The Benoit, Hunting, and Grant Prideco connections are interchangeable with the Tenaris-Hydril connection, but NOT with each other. Tenaris-Hydril no longer markets 2-Step connections, they will continue to support existing material.
Table 17.8. Guidelines for Thread Selection with Wellbore Curvature For a Dogleg Severity
Use
Less than 10◦ /100 ft
Any thread profile, but consult EPT for sizes above 9.625 in (244.48 mm)
From 10 to 20◦ /100 ft
A hook (reverse load flank) thread with an opposing torque shoulder
Greater than 20 /100 ft
A wedge thread
◦
• Size OD–Some connections, API Buttress for example, do not perform as well with increasing diameter. • String Length–The thread profile, thread dimensions and overall thread length will affect the ability of a string to support tubulars below. Note that the required parameter is string length, not string depth. • Dogleg Severity–Depending on the thread profile and the diameter:thickness ratio of the tube, a connection’s use can be limited by the wellbore curvature it is expected to traverse.
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• Pressure Integrity–BP classes threaded connections according to their ability to contain an internal pressure differential (see Section 17.3.3). The terminus of any branch of the tree is a list of recommended connections for the application path that has been selected. The connection selection decision tree focuses on the engineering quality of competing connections. Other factors, not considered in the decision tree, of importance to the decision to use a particular connection include: 1. Availability for the well or project. Can it meet the required delivery date? 2. Availability of backup services from the mill including rethreading services in the area of operations for future repair and refurbishment; 3. Manufacturer’s reputation and quality control/quality assurance procedures; 4. Cost.
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Size ≤ 4-1/2
> 4-1/2, ≤ 11-7/8
> 11-7/8 Go to AA
Type Connections Integral
Either
T&C
Class
Class
2
3
4
1
2
3
4
501 (H) 511 (H) 521 (H) 531 (H) 551 (H)
503 (H) 513 (H) 533 (H) 553 (H) FJL (L) SLF (L) STL (L)
SLSF (L) ANJO (M) SLX (M) 2-Step (L)
BTC (L) LTC (L) EUE (L)
561 (H) SLHT (L)
Bear (L) Blue (M)
563 (H) SLHC (M) TOP (M)
BP Bending Rating
Type Connections Integral
T&C
Either
BP Pressure Rating Class ≤ 7-5/8 and ≤ 4000 ft
1
> 7-5/8
Class
BTC (L) LTC (L)
Class
2
3
4
2
3
4
511 (H) 521 (H)
523 (H) 513 (H) 533 (H) 553 (H) FJL (L) SLF (L) STL (L)
SLIJ-II (L) SLSF (L) ANJO (M) SLX (M) MAC II (M) 2-Step (L)
511 (H) 521 (H)
523 (H) 513 (H) 533 (H) 553 (H)
SLIJ-II (L) SLSF (L) ANJO (M) SLX (M) MAC II (M) 2-Step (L)
2 BOSS (L) SLHT (L) DINO (L) ATS-E (L)
3
4
563 (H) Bear (L) SLHC (M) TC-II (L) TOP (M) Blue (M) HW ST (M) TOP KP (M) TOP HT (M) TOP HC (M)
Figure 17.10. Connection Selection Decision Tree (continued on Figure 17.11)
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AA
Size > 11-7/8, ≤ 13-5/8
> 13-5/8, ≤ 16
> 16, ≤ 18-5/8
> 18-5/8, ≤ 20
> 20, ≤ 36
Class 2
3
4
511 (H) 521 (H) BOSS (L) DINO (L) ATS-E (L) GB-3P (L)
513 (H) 523 (H) HW ST (M)
563 (H) SLHC (M) TOP (M) MAC II (M)
Class Class
Length ≤ 2000 ft
1
2
> 2000 ft
511 (H) 521 (H) BOSS (L) ATS-E (L) GB-3P (L) Class 1
2
3
4
BTC (L)
521 (H) BOSS (L) DINO (L) ATS-E (L)
513 (H) 523 (H) TC-II (L) Blue (M) HW ST (M)
563 (H) SLHC (M) TOP (M) SLIJ II (L) SLSF (L) ANJO (M) SLX (M) MAC II (M)
Class 1
2
RL4/RL1 XLF/XLF-RB QT/MT XLCS/XLCS-RB LEOPARD XLW SWIFT VIPER ALT-2 ST-2 QUIK-STAB QUIK-JAY LYNX MERLIN 2
RL4/RL1 BOSS (L) QT/MT XLF/XLF-RB LEOPARD XLCS/XLCS-RB SWIFT XLW VIPER ATS-E (L) ALT-2 GB-3P (L) QUIK-STAB QUIK-JAY LYNX MERLIN Non-rotating
Class 2
3
4
511 (H) 521 (H) BOSS (L) DINO (L) ATS-E (L)
513 (H) 523 (H) TC-II (L) Blue (M) HW ST (M)
563 (H) SLHC (M) TOP (M) SLIJ II (L) SLSF (L) ANJO (M) SLX (M) MAC II (M)
Figure 17.11. Connection Selection Decision Tree (continued from Figure 17.10)
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Chapter 18
Material Selection and Corrosion Guidelines 18.1
Scope
Two types of service need to be considered when selecting materials for casing strings: • Casing strings that will normally only be exposed to completion brines/drilling muds, but that could be exposed to produced fluids for short periods of time, e.g., the production casing string can be exposed to produced fluids during well work-overs or as a result of production tubing leaks. Materials selection for such strings is covered in Section 18.2. • Casing strings that will/may be exposed to production/injection fluids for a significant part of their life (e.g., liners and some dual completion wells). Materials selection for such items is a complex issue. In addition, materials for such components change frequently as new corrosion-resistant options appear on the market. The selection of materials for such casing strings and for tubing strings is outside the scope of the this manual but is covered in a stand-alone document, Guidelines for Selecting Downhole Tubing and Casing Materials for Oil & Gas Production Wells (2006 Edition), BP ETP Guidance Note GN 036-13 [56].
18.2
Material Selection Process
This chapter contains a flow diagram designed to assist in the selection of casing materials. This flow diagram is not exhaustive. Rather, it flags the major considerations that should be taken into account when selecting materials. With the complex issues involved, it is not possible to ensure that nothing has been omitted from the flow diagram. It is incumbent upon users of the flow diagram to ensure that all necessary aspects have been addressed before making a final material selection. In the flow diagram, decision points at which it will be necessary to consult the relevant specialist(s) have been highlighted. Advice or contacts should be available from one of the materials/corrosion engineers EPT Drilling
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within EPT.
18.2.1
Casing Exposed to Muds and Brines
For strings normally exposed to drilling mud and/or completion brine environments, casing materials are usually carbon or low-alloy steels. There exists a wide range of standard grades available for these steels, as indicated in API Specification 5CT or ISO 11960 [10]. In addition, a number of proprietary grades exist that are not currently contained within the API/ISO standards, e.g., the high strength grades developed specifically for mildly sour conditions, which include 110 ksi strength grades such as Grade C110 and more recently 125 ksi strength grades such as Sumitomo’s SM125S. Typically, final selection of the strength required will be based upon the mechanical requirements of the casing design. Corrosion resistance is not usually a critical issue in the selection of materials for casing strings that are normally only exposed to completion brines and/or drilling muds; hence, carbon or low-alloy steels are normally selected for such casing strings. (Refer to Section 18.3 for corrosion control of completion brines and drilling fluids and to Section 18.4 for external corrosion issues.) There is, however, one significant exception to this rule–the temporary exposure of the casing string to hydrogen sulfide, i.e., sour conditions that can occur, for example, during a well work-over or as the result of a tubing leak. Sulfide stress cracking (SSC) of carbon and low alloy steels, which can result from exposure to sour conditions, can occur very rapidly. In addition, SSC can result in a catastrophic failure, with the material acting in an apparently brittle manner. If sour conditions are anticipated, the use of a casing material/grade that is SSC resistant for the anticipated well conditions is often required. It is common within BP to specify Grade L80 in preference to Grade N80 when available. The L80 grade is fully resistant to SSC, meeting the requirements of NACE MR-0175 or ISO 15156 [66], and is normally little or no more expensive nor more difficult to source than Grade N80. The use of API Specification 5CT or ISO 11960 [10] controlled-hardness grades (such as Grade L80, Grade C90 and Grade T95) for sour service can lead to extremely thick wall designs for high-pressure wells that require sour-service casing. As an alternative, the proprietary high strength grades (e.g., 110 ksi such as Grade C110 or 125 ksi such as SM125S) of sour-resistant casing can be considered. These proprietary, high strength sour-service steel grades cannot be considered fully sour-resistant; however, they are acceptable for mildly sour conditions (cf. Section 18.2.1.3 for further details). A BP specification for the supply of 110 ksi and 125 ksi sour resistant casing is also available [61]. For sour wells, the flowchart in Figure 18.1 can be used when selecting production casing materials that are normally exposed to drilling muds and/or completion brines. Sections 18.2.1.1, 18.2.1.2 and 18.2.1.3 contain further background to the flowchart on selecting materials for sour conditions. 18.2.1.1
Sour-service Exposed to Produced Fluids
NACE Standard MR-0175 or ISO 15156 (Standard Material Requirements–Sulfide Stress Cracking Resistant Metallic Materials for Oilfield Equipment) [66], together with BP ETP GP 06-10 (Materials for Sour Service), is recommended to define a sour environment for BP worldwide. Sour service is defined in NACE MR-0175 or ISO 15156 as exposure to oilfield environments that contain H2 S and can cause cracking of materials by the mechanisms addressed by NACE MR-0175 or ISO 15156. EPT Drilling
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Figure 18.1. Materials Selection Production Casing Strings Normally Exposed to Completion Brines/Drilling Mud
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These mechanisms include sulfide stress cracking (SSC), hydrogen induced cracking (HIC), etc. The only materials prone to HIC are carbon and low-alloy steels; CRAs are not prone to HIC. In addition, for most downhole applications, the materials used (i.e., seamless tubulars) are not prone to HICrelated problems as long as the sulphur content of the steel is controlled (e.g., NACE MR-0175 or ISO 15156 Part 2 recommends maximum sulphur levels of 0.01% for seamless pipe and 0.025% for forgings in carbon/low-alloy steels), which is a normal requirement of tubular material specifications. Therefore, for most circumstances, specific consideration of HIC is not required when selecting downhole tubular materials. The major consideration when selecting materials for sour service is resistance to SSC. This is the focus of these guidelines. NACE MR-0175 or ISO 15156 recognizes that water (as a liquid) is required for the cracking mechanisms addressed. Hence, theoretically, for wells producing only dry gas or dry gas injection wells, the resistance of materials to these cracking mechanisms would not be required. In such cases, however, the presence of water, even if only for short periods, cannot be totally discounted (e.g., water wetting may occur during process upsets, at start-up or during shut-ins). Therefore, in such cases the presence of water shall be assumed to be a possibility, and the designation of the well as “sour” or otherwise with reference to SSC resistance should be based on the partial pressure of hydrogen sulfide, which can be determined as described below. To establish service conditions using mole % H2 S or ppm H2 S in the gas phase, refer to the following equations: • From mole % H2 S in the gas phase, Mole % H2 S × Pressure. 100
(18.1)
Mole ppm H2 S × Pressure. 1, 000, 000
(18.2)
Partial Pressure of H2 S = • From ppm mole H2 S in the gas phase, Partial Pressure of H2 S =
For downhole conditions, the pressure to use should represent the maximum pressure that can occur in the produced fluids to which the tubular string could come into contact. Typically, for gas wells use the bottom hole pressure, and for oil wells use the higher of the bottom hole pressure and the bubble point pressure. Ideally the gas composition used should be that which would occur at the pressure of interest (i.e., the bottom hole pressure or bubble point pressure). If this is not available, however, then the use of the gas composition at a lower pressure (e.g., from a separator) will provide a conservative assumption. NACE MR-0175 or ISO 15156 defines a number of regimes for “sourness” for steels with respect to SSC resistance. One of these, Region 0, addresses conditions for which consideration of the SSC resistance of candidate materials is not normally required. The advice for Region 0 within NACE MR-0175 or ISO 15156 is that normally no precautions are required for the selection of steels for use under these conditions. Nevertheless, a number of factors that can affect a steel’s performance in this region should be considered, as follows: • Steels that are highly susceptible to SSC may crack. EPT Drilling
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• The physical and metallurgical properties of the steel affect its inherent resistance to SSC. • Very high strength steels can suffer SSC in aqueous environments without H2 S. Above approximately 965 MPa (140 ksi) yield stress, attention may be required to steel composition and processing to ensure that these steels do not exhibit SSC in Region 0 environments. • Stress concentrations increase the risk of cracking. The requirements for Region 0 do not infringe on material selection for downhole conditions except under the most exceptional cases. Hence they are not considered further in these guidelines. For the purpose of these guidelines, “sour” refers to conditions where the partial of pressure of H2 S exceeds that for Region 0 (i.e., 0.05 psia) of NACE MR-0175 or ISO 15156, and “sweet” refers to conditions where the partial of pressure of H2 S is less than that for Region 0 (i.e., less than 0.05 psia = 0.003 bara). The properties of well fluids may change during the lifetime of the well. Events such as reservoir souring can produce more arduous service conditions and must be considered during the material selection process. 18.2.1.2
NACE Standard MR-0175 or ISO 15156 “Standard Approach”
The prime concern for casing strings with respect to NACE Standard MR-0175 or ISO 15156 [66] is the resistance of materials to SSC in sour conditions. In some regions, such as the state of Texas in the United States, the standard is a legislative requirement, i.e., it must be applied there. NACE MR-0175 or ISO 15156 can be referenced for initial information on materials with adequate resistance to SSC for sour conditions. The BP application limits for some alloys, however, are more restrictive than those indicated in NACE MR-0175 or ISO 15156 . Hence it is important to reference the relevant BP ETP (GP 06-20) and these guidelines before finalizing materials selection. NACE MR-0175 or ISO 15156 allows the selection of carbon/low-alloy steels that are suitable for all sour conditions and all temperatures using Option 1 of NACE MR-0175 or ISO 15156 Part 2 and via their listing in NACE MR0175 or ISO 15156 Part 2 Appendix A, Clause 2 “SSC-resistant carbon and low alloy steels and the use of cast irons”. (Section A.2.2.3 deals specifically with downhole tubular materials.) In addition, increasing the temperature reduces the likelihood of sulfide stress cracking for many (but not all) materials. This is particularly the case for carbon/low-alloy steels. Hence NACE MR-0175 or ISO 15156 allows the use of carbon/low-alloy steels with a specified minimum yield strength above that of the fully sour-resistant grades under circumstances where the minimum operating temperature is above certain limits. NACE MR-0175 or ISO 15156 details the acceptable tubular material grades for different temperature ranges (cf. Table 18.1). This information has been incorporated into the flowchart in Figure 18.1 of these guidelines. When using these criteria, it is important to bear in mind that SSC can occur within a relatively short time span, so that periods of exposure to sour conditions at temperatures below those stated in the table could potentially lead to SSC problems. For this reason it is important to note that the temperature levels quoted in Table 18.1 are the minimum operating temperatures the casing will experience. If temperatures below this minimum are expected, even for short periods of time, then the non-sour, higher strength materials should not be used. EPT Drilling
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Table 18.1. Acceptable API Specifications for Tubular Goods For all Temperaturesa,b
For Operating
For Operating
For Operating
Temperatures 65 C (150◦ F) or Greaterc
Temperatures 80 C (175◦ F) or Greaterc
Temperatures 107◦ C (225◦ F) or Greaterc
API Spec 5CT Grades N80(Q&T); C95
API Spec 5CT Grades H40; N80; P110
API Spec 5CT Grade Q125e
Proprietary grades per NACE MR-0175
Proprietary Q&T grades with 110 ksi or
Proprietary Q&T grades with 140 ksi or
Section 10.2
less maximum yield strength
less maximum yield strength
◦
API Spec 5CT Grades H40d ; J55; K55; L80
◦
(Type 1); C90 (Type1); T95 (Type 1)
a b
Impact resistance may be required by other standards and codes for low operating temperatures.
Casing with 155 ksi yield strength is not covered in this table and is unsuitable for sour-service
conditions at any of the temperature ranges specified. c
Continuous minimum temperature; for lower temperatures, select from Column 1.
d
For Grade H40 material the maximum permissible yield strength is 80 ksi.
e
Regardless of the requirements for the current edition of API Spec 5CT, Grade Q125 shall always (1)
have a maximum yield strength of 150 ksi, (2) be quenched and tempered and (3) be an alloy based on Cr-Mo chemistry. The C-Mn alloy chemistry is not acceptable.
18.2.1.3
BP NACE Standard MR-0175 or ISO 15156 “Qualifying Materials for Specific Conditions”
NACE MR-0175 or ISO 15156 allows that materials, whether included in the pre-qualified listings in the standard or not, can be qualified for a particular service environment (of known in situ pH and pH2 S). This qualification can take the form of appropriate laboratory tests and/or documented satisfactory service history. (The standard also gives advice on what appropriate laboratory tests are.) On the basis of this, BP has developed “domain diagrams” (plots of H2 S vs. pH showing domains where the material has adequate SSC resistance) based upon laboratory test results (using laboratory tests based upon the appropriate tests indicated in NACE MR-0175 or ISO 15156) and field experience, which allows the user to select the most cost-effective material for the intended service. All testing for the BP methodology is conducted under ambient (24◦ C ± 3◦ C) temperature conditions, i.e., a worst case scenario. Therefore, the methodology described here is applicable to all likely operating temperatures. This methodology need not be applied to the traditional sour resistant grades in API 5CT or ISO 11960 (i.e., Grade L80, Grade C90 and Grade T95), which are assumed suitable for all sour conditions on the basis of past experience and test data. To apply the BP methodology, it is necessary to know certain information about the proposed well, i.e., EPT Drilling
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the partial pressure of hydrogen sulfide in the gas phase and the in situ pH of the water associated with the produced fluids. If no in situ pH data is available, then the computer model embedded in the guidelines for selecting downhole tubular materials [56] can be used to assess the in situ pH on the basis of certain well information. Once the necessary information has been collected, the conditions can be plotted onto the appropriate SSC performance domain charts for individual alloys at the end of these guidelines. There are two domains identified on the individual alloy charts: 1. If the operating conditions fall within the acceptable domain, then the material is likely to have an acceptable resistance to SSC under the prevailing conditions. The charts were developed, however, on limited information, i.e., it was only possible to test a selection of the wide range of materials available on the market and only at one time. (Manufacturing techniques can change with time, which may also affect their SSC resistance.) Therefore, it is important to check the resistance of the material to the anticipated conditions before finalizing the selection of a non-sour material grade for potentially sour service. The suitability can be confirmed in two ways: • From prior satisfactory testing or service experience with material from the same supplier and made by the same manufacturing route under conditions equivalent to or worse than the intended service; • From the successful outcome of small scale SSC laboratory tests under test conditions representative of the intended service on material from the same supplier and made by the same manufacturing route. Material testing lead times of perhaps eight weeks need to be considered in planning. For further information contact the relevant specialist. 2. If the operating conditions fall within the unacceptable domain, then it will be necessary to consider a material with greater SSC resistance. The domain charts are not all encompassing but only deal with resistance to SSC.
18.3
Internal Corrosion Control
It is necessary to consider the two different types of well operations: • drilling operations (e.g., exploration/appraisal wells); • production operations (e.g., development wells).
18.3.1
Drilling Operations (Exploration/Appraisal Wells)
In the case of oil-based muds, there is little danger of corrosion problems under normal operating conditions, since oil is the continuous phase in the mud, and the metal surface will be oil-wet. The major exception to this is the contamination of the mud with water and acid gases (i.e., CO2 and/or H2 S) due to formation fluid inflow. Therefore, it is important to ensure that the drilling fluid hydrostatic head and drilling fluid EPT Drilling
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Figure 18.2. Sulfide Stress Cracking Performance Domain of Grade N80 Carbon Steel
density are maintained to minimize this inflow. In addition, it may be necessary to make chemical additions to oil-based muds, e.g., sulfide scavengers. The dissolved gas that most commonly determines the general corrosivity of water-based drilling muds is oxygen, although the insurgence of acid gases due to formation fluid inflow may also be important. In casing design, general corrosion of the type associated with oxygen or acid gases is not normally an issue as the periods of exposure are relatively short. In addition, the pH of the mud is controlled to minimize the likely corrosion rate. An important corrosion problem that can occur during drilling is sulfide stress cracking (SSC), which occurs as a result of hydrogen sulfide in the mud. This hydrogen sulfide can have a number of sources, the more important being: • Inflow of formation fluids containing hydrogen sulfide; • Bacterial activity; • Degradation of the mud. The second and third of these sources can be adequately controlled by the addition of biocides to the mud and correct mud selection. Although the likelihood of the first source can be reduced by maintenance of the drilling fluid hydrostatic head and drilling fluid density to minimize formation fluid inflow, the possibility EPT Drilling
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Figure 18.3. Sulfide Stress Cracking Performance Domain of Grade P110 Carbon Steel
of such inflow must still be considered; even a short exposure time to a sour environment can lead to a potentially catastrophic failure. Therefore, if the presence of hydrogen sulfide is expected, additional preventative measures need to be taken to ensure that SSC will not occur, for example: • Maintain the pH at a value of 10 or higher to neutralize the hydrogen sulfide; • Use chemical sulfide scavengers. In addition, consideration can be given to the use of sour resistant casing materials (cf. Section 18.2.1.1). For wells which are expected to be sour, it is normal practice within BP to use sour-resistant casing grades for the casing strings likely to be exposed to the sour fluids in the absence of appropriately treated drilling mud. In the case of high-temperature/high-pressure wells, the situation was somewhat more complex for UK sector North Sea applications in the past. Document CSON 59, produced by the Department of Environment, required the operator to provide supporting data that non-sour casings can be relied upon not to fail catastrophically during: • A temporary period of exposure to sour reservoir fluid (e.g., while circulating out a kick or if there is a leak in the test string during production testing) and not subsequently thereafter in the remainder of its service life, or EPT Drilling
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Figure 18.4. Sulfide Stress Cracking Performance Domain of C110 (Sour Resistant Grade) Low-Alloy Steel
• The time between first exposure to sour reservoir fluids and completion of evacuation of the drilling installation in the event of total displacement of the well bore contents to such fluids. These requirements have led operators to consider thick-wall sour resistant casing or proprietary highstrength sour-resistant grades (normally up to 110 ksi minimum specified yield strength). These are discussed in the section on materials selection (Section 18.2), and reference should be made to that section before specifying these types of material. CSON 59 has now been superseded by PON 13, which imposes no requirement other than notification of expected H2 S and incident reporting to PON 11.
18.3.2
Production Operations (Development Wells)
Well design should endeavor to contain the corrosive produced fluids within the production tubing, e.g., by the correct selection of tubing material and the use of tubing strings with premium connections, where necessary. Therefore, the prime consideration in accounting for corrosion in well casing design is to ensure the correct selection of the annulus fluid. It is recognized, however, that tubing leaks and subsequent pressurized annuli are possibilities. Therefore, measures need to be taken to ensure the adequate protection of the casing under such circumstances. This is a major reason why casing materials with adequate sour resistance should be selected for production casing, since cracking mechanisms associated with sour conditions can occur very rapidly after exposure (within a few days). EPT Drilling
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Figure 18.5. Sulfide Stress Cracking Performance Domain of SM125S Low-Alloy Steel (for Casing
Any part of the casing that is likely to be exposed to the produced fluids for a significant length of time should be designed to withstand such an environment. When designing such casing, considerations very similar to those given for production tubing need to be addressed when selecting materials. This area is addressed in Guidelines for Selecting Downhole Tubing and Casing Materials for Oil & Gas Production Wells (2006 Edition), BP ETP Guidance Note GN 036-13 [56]. 18.3.2.1
Corrosion Control in Completion Fluids
A completion fluid can be defined as any borehole fluid placed across the producing zone prior to bringing on a well. These fluids are field/well specific and fulfil many roles. Brine completion fluids are used in well testing operations, work-overs, completions and as packer fluids. The function in a completion is to fill the annulus space between the production tubing and casing. Completion fluids are commonly brines and are selected based upon the required specific gravity. Examples of some of the brines used and the specific gravity ranges they cover are given in Table 18.2. A number of chemical additives can be made to these muds to assist in corrosion control: 18.3.2.1.1
Biocide Biocide is added to prevent the growth of aerobic and/or anaerobic bacteria. Such
bacteria can lead to corrosion problems by the production of hydrogen sulfide. Therefore, it is necessary EPT Drilling
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Table 18.2. Typical Brines used as Completion Fluids Brine
Specific Gravity Range
PPG
Sea Water
1.02
8.5
KCl
1.16
9.7
NaCl
1.19
10.0
NaBr
1.50
12.5
CaCl2
1.39
11.6
CaBr2
1.39 to 1.71
11.6 to 14.3
ZnBr2 /CaBr2 /CaCl2
1.82 to 2.31
15.2 to 19.3
to prevent their activity. There are a number of biocides commercially available. Final selection will be based upon many factors. One of the most important factors, however, is the salinity of the completion brine. Where the brine salinity is high (typically taken as greater than 12% wt/wt), the addition of a biocide is often unnecessary, as the high salinity is sufficient in itself to prevent bacterial activity. Another factor that will affect the selection of a suitable biocide is the compatibility with an oxygen scavenger (if present). Therefore, it is important to get the input of a suitable specialist when selecting biocides for completion brines.
18.3.2.1.2
Oxygen Scavenger An oxygen scavenger is required to remove dissolved oxygen from the com-
pletion brine to reduce its corrosivity. The chemicals most commonly used for this function are ammonium or sodium bisulphite. The dosage rate will depend on the oxygen content of the brine. It is important to avoid significantly overdosing the oxygen scavengers, as these can be corrosive in their own right and/or can lead to the deposition of iron sulfide scales. It is recommended that the oxygen level of the treated fluid be monitored to ensure effective treatment. If the completion brines are not deaerated, the available oxygen may in any case be quickly consumed by the superficial corrosion of the carbon/low alloy casing where the two are in contact. Therefore, a decision must be made on whether an oxygen scavenger is required. This decision can be based upon a number of factors. For example, even the short period of enhanced corrosion in non deaerated solutions may produce significant quantities of corrosion product. There may be concerns that this corrosion product dropping to the bottom of the annulus will block injection valves. Therefore, future use of the annulus needs to be considered. Additionally, if corrosion-resistant alloy (CRA) tubulars are specified, then the presence of oxygen may initiate corrosion, e.g., pitting corrosion, crevice corrosion, galvanic corrosion or even stress corrosion cracking, especially if the oxygen is not rapidly consumed by superficial corrosion of carbon/low alloy steel (e.g., if the fluids are inside the tubing for any reason, or other areas where carbon steel is not present in the region of CRA tubulars). If in any doubt, the relevant specialists should be consulted. EPT Drilling
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18.3.2.1.3
Corrosion Inhibitor Some high-density brines can be corrosive in their own right (e.g., zinc
bromide). In such circumstances it will often be necessary to use a film-forming corrosion inhibitor to reduce the corrosion rates to permissible levels. Selection of a corrosion inhibitor should be made with care. Compatibility with the formation itself should also be considered to avoid formation swelling or blocking. It is recommended that due reference be made to the relevant specialists. 18.3.2.1.4
Scale Inhibitor This chemical additive is not added to control the corrosivity but rather to
prevent scales forming when the completion brine comes into contact with formation brine. If a compatible completion brine has been selected, or where the completion brine will not come into contact with formation fluids, a scale inhibitor is unnecessary. For example, where a sodium-based or potassium-based brine is used, the high solubility of the products formed by mixing with formation water means that the addition of a scale inhibitor is unnecessary. Under normal conditions, scale inhibitors are only necessary in calcium chloride/bromide completion brines. Under such circumstances, it is recommended that the relevant specialist be contacted. To avoid corrosion problems resulting from completion fluids, the use of alternative non-aqueous fluids is sometimes considered, e.g., diesel. It has been found that one alternative fluid (bromoil/densoil) can be corrosive at elevated temperatures (> 400◦F, 200◦ C). Therefore, care needs to be exercised when using these types of fluid. When selecting the chemical treatment package for completion brine, it is important to refer to the BP Guidelines (BP ETP GN 06-004–Selection and Treatment of Acids, Scale Dissolvers and Clear Brines to Avoid Corrosion Failure, 2007 Edition [55]) and contact the relevant specialist(s) to ensure the suitability/compatibility of the various additives.
18.4
External Casing Corrosion
External corrosion of casing can be a serious problem, especially where the casing passes through aquifers or ground water. If such problems are expected or encountered, consideration needs to be given to either cementing across the zone of concern to seal the casing or, if this is not possible, external corrosion protection. The design of such systems is outside the scope of this manual, and reference should be made to the appropriate specialists. The following offers some preliminary guidance: • The preferred option is to seal the casing in the corrosive region by executing an effective cementing job. • Where this does not prove possible, then the cement should be supplemented by applying cathodic protection across the corrosive region. The design of cathodic protection systems for casing is covered by NACE document SP-0186 [67]. • It may be necessary, where cement jobs are particularly poor, to consider externally coating the casing with a standard two-part epoxy paint system in order to reduce the demand on the cathodic protection system. EPT Drilling
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Anode
Fe 1 Fe++ + 2 electrons
Current Row Cathode
Electrolyte
2H+ + 2 electrons 1 H2 (Gas) Metal
Figure 18.6. Diagrammatical Representation of the Corrosion Process for Iron
• Where adequate cementing/cathodic protection is not possible (e.g., where casing passes through conductors), it may be necessary to consider the use of an inhibited gel system that can be injected into the casing annulus (which also helps displace any water). It will be necessary, however, to ensure that the chemical package selected will not result in supplementary problems (such as microbiologically induced corrosion). Contact the relevant specialist(s).
18.5
Corrosion Background
A prerequisite for corrosion to occur is the presence of an aqueous phase, although even a trace of water can lead to corrosion. Corrosion is an electrochemical process, so an electrical current flows during corrosion. For an electrical current to flow, there must be a driving force, i.e., a voltage source, and a complete electrical circuit. The voltage source is the metal itself. All metals contain stored energy, e.g., as a result of refining or mechanical working. Metal will adopt an electrical potential when it is put into an aqueous solution, known as the equilibrium potential. The electrical circuit consists of three parts. These are shown schematically in Figure 18.6 and consist of: The Anode which is the portion of the metal surface which is dissolving or corroding. For iron this can be represented by the chemical reaction: F e ⇒ F e2+ + 2 electrons. EPT Drilling
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The Cathode which is the portion of the metal surface at which the electrons formed by the anodic reaction are consumed. There are many cathodic reactions that can occur, depending on the composition of the solution. For an acid, the cathodic reaction would typically be: 2H + + 2 electrons ⇒ H2 (gas). The Electrolyte which is the electrically conductive solution on the metal surface through which the electrical current (or electrons) necessary to support the corrosion process flows. If there is no externally applied electrical current, the anodic and cathodic reactions are balanced, and there will be no “total” current flow measured. The reasons why some areas of the metal surface act as anodes, whereas others act as cathodes, are complex. A major factor is inhomogeneity in the metal surface and/or electrolyte. In general corrosion, the anodes and cathodes will be randomly distributed over the surface and will “move” during the corrosion process. In localized corrosion, e.g., pitting, the anodes will be restricted to certain, small areas. Many different types of corrosion damage can occur. The more likely to be experienced by downhole casing can be classified as follows: 1. General Corrosion. This results in a fairly uniform loss of material across the surface of a component, leading to a loss in load carrying capacity, e.g., the ability to contain a pressure, tension or collapse. 2. Localized Corrosion. This results in uneven wastage of the component e.g., pitting corrosion. Pitting corrosion is a particularly damaging form of corrosion in which components can fail by perforation with only a small percentage weight-loss. In addition, pits will act as stress concentrators, reducing the loadcarrying capacity of the component. Alternatively, localized corrosion may occur at particular locations, e.g., crevices, mixed metal sites (galvanic attack) and areas of high turbulence (erosion-corrosion). 3. Environment-Sensitive Cracking (ESC). These mechanisms can lead to catastrophic, brittle failures. Cracking can occur rapidly and without the accompaniment of significant material wastage. In addition, the cracks can be very fine, making them difficult to detect using conventional inspection techniques. Examples of ESC are sulfide stress cracking (SSC), chloride stress corrosion cracking (CSC) and corrosion-fatigue.
18.5.1
Corrosion Mechanisms
As has already been indicated, there exist many mechanisms by which corrosion damage can occur. This section covers the corrosion damage that can be accrued as a result of chemical contaminants and some of the other corrosion mechanisms that must be considered in casing design. 18.5.1.1
Carbon Dioxide
Carbon dioxide is commonly found associated with well fluids. Carbon dioxide dissolved in water forms a weak acid (carbonic acid) that can cause corrosion. This is of particular importance for carbon steel, in which case an iron carbonate film is sometimes formed on the metal surface. CO2 corrosion of carbon steels often occurs at locations where the iron carbonate film is deficient, resulting in a particular form of EPT Drilling
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localized pitting corrosion known as “mesa” attack. In circumstances where there is no iron carbonate film, the corrosion will be general. The rate of CO2 corrosion will depend on a number of factors, including CO2 partial pressure, pH, temperature, flow velocity and the presence and nature of other chemical species (e.g., oxygen, chlorides or H2 S). There are numerous guidelines that can be used to predict the severity of CO2 corrosion. Contact the relevant specialist. 18.5.1.2
Hydrogen Sulfide
There exist a number of possible sources of hydrogen sulfide in downhole fluids, including: • Associated with the well fluids; • Generated as a result of bacterial activity. In this case sulphate reducing bacteria (SRBs) can reduce sulphates in the fluids to hydrogen sulfide; • Breakdown products of chemical species in the fluids. One such source could be bisulphites added to remove oxygen from injection water. Hydrogen sulfide dissolved in water can react with a steel surface, producing an iron sulfide scale. H2 S corrosion often results in deep pits in regions where the iron sulfide scale is not present. In practice, this type of H2 S corrosion has little practical significance unless the H2 S content is high, i.e., several mole percent. Of greater importance, at the relatively low H2 S levels often found in downhole fluids, is the mechanism known as “sulfide stress cracking” (SSC). Sulfide stress cracking occurs as a result of the entry of atomic hydrogen into the metal. Aqueous corrosion will produce atomic hydrogen which would normally tend to recombine via the reaction: 2H + + 2 electrons ⇒ H + H ⇒ H2 (gas) These hydrogen gas molecules are too large to enter the metal and are thus not harmful to it. However, hydrogen sulfide is thought to discourage the recombination of hydrogen atoms to form H2 gas and hence encourage the entry of atomic hydrogen into the metal. Once in the metal the atomic hydrogen will diffuse to trap sites, where it will lead to a local increase in the stress and/or a reduction in the strength of the metal lattice. For a material under load, there is evidence to suggest that the atomic hydrogen will concentrate near stress concentrators and may give rise to crack initiation at such points, hence leading to a brittle-like fracture. This type of cracking can occur quite rapidly. Thus, even if materials are only to be exposed to sour conditions for short periods of time, they must be resistant to SSC. This aspect is covered in some detail in Section 18.2. 18.5.1.3
Oxygen
The presence of dissolved oxygen can have a marked influence on the corrosion of oil-field goods. High corrosion rates can result even at relatively low concentrations of dissolved oxygen (less than 100 ppb). In EPT Drilling
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this process iron is converted by a corrosion reaction to oxides and/or hydroxides. The cathodic reaction in this case is: O2 + 2H2 O + 4 electrons ⇒ 4OH − The corrosion rate in oxygenated near-neutral solutions is often controlled by the rate at which oxygen can diffuse to the cathodic areas to support the corrosion reaction. As such, the corrosion rate will be increased by flow, etc. Oxygen corrosion is not normally a problem with produced fluids, as they contain no dissolved oxygen. It can be a significant issue in water-based drilling muds, however, in which case it may be necessary to control the dissolved oxygen content using oxygen scavengers. Another area where oxygen corrosion can be a significant issue is in injection water systems, in which case care must be taken to reduce the dissolved oxygen to acceptable levels, e.g., using gas stripping or vacuum degassing. 18.5.1.4
Halide Ions
Halide ions, e.g., chloride and bromide ions, are present in many of the fluids likely to be encountered downhole, i.e., formation waters, injection waters, completion brines, work-over fluids, etc. Halide ions can cause localized corrosion damage to materials used for downhole equipment in the form of corrosion pitting and/or crevice corrosion. In addition, they can increase the corrosion damage resulting from the effect of other corrodents. Halide ions can also give rise to stress corrosion cracking (SCC) of susceptible materials, principally austenitic stainless steels. This type of cracking will normally only occur at elevated temperatures, typically above 50◦ C (120◦ F) for austenitic stainless steels, and under the action of tensile stresses. This can also include residual stresses from mechanical working. Stress corrosion cracking can be defined as crack initiation and growth in an alloy caused by the conjoint action of corrosion and tensile stress. This cracking can occur at stresses well below the yield strength. The mechanism by which this occurs is not fully understood, but it requires the presence of certain specific alloy/environment combinations, e.g., austenitic stainless steel in chloride-containing solutions. The result of SCC is that normally ductile materials can suffer from catastrophic, apparently brittle failures. 18.5.1.5
Galvanic Corrosion
Galvanic corrosion is the preferential corrosion that can occur to one of the metals, when two different metals are electrically coupled in a corrosive environment. In such a couple, one of the metals will act as an anode (i.e., it will corrode at an enhanced rate), and the other will act as a cathode (i.e., there will be a certain degree of protection). The susceptibility of a material couple towards galvanic corrosion of the anodic metal (i.e., the metal with the lower equilibrium potential) is influenced by a number of factors, such as the conductivity of the corrosive medium, the relative surface area of the two metal components and the difference in the equilibrium potentials of the two metals in the corrosive environment. 18.5.1.6
Localized Corrosion
There are two types of localized corrosion that are likely to be encountered downhole, i.e., corrosion pitting and crevice corrosion. As already indicated, corrosion pitting occurs when certain regions in the metal act EPT Drilling
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as strong anodes. An example of this is the corrosion pitting of certain stainless steels in chloride-containing environments. In this case, pitting is enhanced by the presence of dissolved oxygen. The pitting process is strongly affected by temperature. There are often temperatures below which corrosion pitting will not occur in a particular environment, which is known as the critical pitting temperature. Pitting is more damaging than general corrosion as it can result in penetration in much shorter times and is more difficult to detect. This is an aspect that should be born in mind when selecting materials for downhole service, particularly corrosion resistant alloys. Crevice corrosion is the localized damage that can result at a narrow gap or crevice between two adjacent components. The crevice may be between two similar materials, two different materials (in which galvanic corrosion may also play a role) or even between a metal and a non-metal (e.g., elastomers). An important factor in determining whether crevice corrosion will occur is the size of the gap. Crevice corrosion is often exacerbated at higher temperatures. The local environment produced within a crevice can be quite different to the bulk fluid environment, leading to corrosion damage that could not be predicted from the general fluid composition.
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Chapter 19
Kick Tolerance 19.1
General
Kick tolerance is an estimate of the volume of a gas influx at bottom hole conditions which can be safely shut-in and circulated out of the well. Previous editions of the BP Tubular Design Manual included a procedure to calculate kick tolerance in vertical wells. This material has been extended to include deviated wells in Section 5 Volume 1 of the BP Well Control Manual [15]. For kick tolerance calculations, reference should now be made to the BP Well Control Manual but in the case of gas kick profile mechanical design of casing the volumes and kick intensities used are to be at least those in Chapter 9 of this manual.
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Chapter 20
Tubular Catalogue 20.1
Introduction
In addition to the performance properties of the tube and connector, specification of a tubular string element includes grade and dimensional considerations that may or may not be covered by industry standards. This section provides background information on tubular specifications and is intended to inform drilling engineers on specification and procurement issues. These issues are usually pursued by specialists in either EPT or procurement and so are discussed here more for information than direct use. The Standard BP Inventory is a list of weight/grade/thread combinations intended to encompass most OCTG needs and provide cost benefits via large volume procurement master agreements. The first attempt at a design should always restrict the available inventory to this list. In instances where the size and/or strength range provided by the Standard Inventory is inadequate to meet design requirements, substitutes will naturally be required. Choice of pipe outside the standard inventory should be fully discussed with EPT for technical soundness and procurement since there may be large cost and delivery schedule issues to be considered. The performance properties of unworn casing should be calculated from formulas presented in API TR 5C3 or ISO TR 10400 [9] using minimum yield and ultimate strengths as specified in API Specification 5CT or ISO 11960 [10]. Proprietary vendor performance properties such as “high collapse” are in general not acceptable without detailed technical review. Tubes designated as proprietary can be used, however, provided the design is performed using API mechanical properties and formulas (example: a vendor’s HC95, “high collapse”, 95,000 minimum yield strength tube may be used in a design, provided it is rated as Grade C95). In instances where two API grade designations are possible, for example Grades N80 and L80, the grade having the weaker mechanical properties should be used in rating the vendor’s proprietary tube.
20.2
Standards
API Specification 5CT, Specification for Casing and Tubing and ISO 11960, Petroleum and Natural Gas Industries–Steel Pipes for Use as Casing or Tubing for Wells [10] are the industry standards for the manufacture, testing and inspection of OCTG and should always be considered the minimum acceptable standard EPT Drilling
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when purchasing new pipe. Neither API Specification 5CT nor ISO 11960 [10] addresses used tubulars. The documents are the same in format and content; specifying manufacturing to one or the other results in the same product. Information on the inspection and application of used tubulars can be found in BP GIS 02-208 Used OCTG. Additional references of note include BP GIS 02-201 Specification for OCTG Seamless Casing and Tubing, BP GIS 02-204 Specification for Sour Service Grades C110 and C125 Low Alloy Steel OCTG Seamless Pipe and BP GIS 02-206 Specification for Duplex and Super Duplex 25% Chrome Stainless Steel Seamless Pipe.
20.3
Groups
OCTG is divided into four groups by grade to better define manufacturing, testing and inspection criteria. Table 20.1 shows the four groups, the grades in each group, and manufacturing process and heat treatment for each grade. Each grade designation consists of a letter and a number. The letter has no real significance. The number designates the minimum yield strength of the steel in 1000 psi. For example, Grade P110 is a Group 3 steel with a minimum yield strength of 110,000 psi. Grades of steel with letter designations other than those in Table 20.1, for instance HC95, is not recognized by API and is not controlled by API manufacturing and inspection requirements. The manufacturing and quality requirements are those agreed to by the purchaser and the manufacturer.
20.4
Manufacturing Process
The manufacturing process is either seamless (SMLS) or electric welded (EW). The SMLS process takes a solid billet, usually round, that is heated and rotary pierced. After piercing, the billet is elongated, and the walls are thinned to produce a seamless tube. Several different types of equipment are used to produce seamless pipe. The plug mill, pilger mill, mandrel mill and retained mandrel mill are examples. The EW process takes a continuous coil of flat steel with the desired final wall thickness, called skelp, forms it into round tube, and welds the longitudinal seam. The high frequency resistance or induction welder heats the edges of the rounded coil to around 1400◦C (2600◦ F) as the edges are squeezed together to produce a forge weld. No filler or welding rod is used. The resulting internal and external weld flash are removed. Individual lengths are then cut from this continuous tube. As indicated in Table 20.1, a specified method of full length heat treatment is given for each grade. The heat treatment of SMLS and EW pipe takes place after rolling and ranges from “as rolled” (none) for some Group 1 grades to quenched and tempered (Q&T) for grades in Groups 2, 3 and 4. Grades J55, K55 and N80 may also be heat treated using the normalized (N), or normalized and tempered (N & T) methods. Heat treatment is required to obtain the higher yield strengths and develop desired ductility and toughness. • The Q&T process involves heating individual tubes to approximately 870 to 930˚C (1600 to 1700˚F) in an austenizing furnace, then allowing the tubes to soak at this temperature for a specified amount of time depending on the chemistry of the steel, the thickness pipe and the specific mill. The evenly heated tube is then rapidly quenched, or cooled, to below 93˚C (200˚F) using water or oil as the EPT Drilling
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Table 20.1. Process of Manufacture and Heat Treatment (API Specification 5CT or ISO 11960 [10]) Group
1
2
Grade
Type
Process of
Heat
Manufacturea
Treatment
H40
S or EW
None
J55
S or EW
Noneb
K55
S or EW
Noneb
1
S or EW
c
N80
Q
S or EW
Q&T
S or EW
(see Note)
S or EW
Q&T
1050
e
1100
M65 1
L80
9Cr
S
Q&T
L80
13Cr
S
Q&Te
1100
C90
1
S
Q&T
1150
C90
2
S
Q&T
1150
S or EW
Q&T
1000
C95
b
F
N80
L80
a
◦
T95
1
S
Q&T
1200
T95
2
S
Q&T
1200
S or EWf,g
Q&T
1
S or EWg
Q&T
Q125
2
g
S or EW
Q&T
Q125
3
S or EWg
Q&T
Q125
4
S or EWg
Q&T
3
P110
4
Q125
S = seamless process; EW = electric-welded process.
Full length normalized (N), normalized and tempered (N & T), or quenched and tempered (Q&T),
at the manufacturer’s option or as specified on the purchase agreement. c
Full length normalized or normalized and tempered at the manufacturer’s option.
e
Type 9Cr and 13Cr may be air-quenched.
f
Special chemical requirements for electric-welded Grade P110 casing are specified in Table C.5.
g
Special requirements unique to electric-welded Grade P110 and Grade Q125 are specified in A.5 (SR11). EPT Drilling
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cooling medium. After quenching, the pipe is reheated, or tempered, to approximately 560 to 650˚C (1050 to 1200˚F) in a tempering furnace and then allowed to air cool to room temperature. • The N&T process involves heating individual tubes in an austenizing furnace, allowing the tubes to air cool, reheating them in the tempering furnace, and then allowing them to air cool to room temperature again. • Normalizing involves heating individual tubes in an austenizing furnace and allowing the tubes to air cool to room temperature. EW pipe must also have the weld seam heat treated, or seam annealed, to above 540◦C (1000◦ F) to relieve the stresses of welding and produce a normalized grain structure. The ductility of the weld and heat affected zone (HAZ) is increased if the weld seam is heat treated to above 840◦ C (1550◦ F).
20.5
Chemistry
Another element important in the manufacture of OCTG is the chemistry of the steel. Table 20.2 lists the minimums and maximums for the various required elements of each grade. Note that Grades C90 and T95 have two different types, and Grade Q125 has four different types. Historically, end user and mill representatives writing the API standards could not agree, so more than one type was specified. In all three cases it is best to specify Type 1 chemistry because more elements are controlled, and maximum phosphorous and/or sulfur is lower. Grade L80 has three types, but each has a specific purpose: • Type 1 is a sulfide stress cracking (SSC) resistant steel with 80 ksi minimum yield strength; • Type 2 has 9% chromium added for resistance to CO2 corrosion and is usually used for manufacturing tubular accessories; • Type 3 has 13% chromium added for more resistance to CO2 corrosion. Types 2 and 3 have limited resistance to SSC.
20.6
Inspection and Testing
After rolling, the rest of the pipe manufacturing process is devoted to inspection and testing, and is a quality assurance process to prove that the tube is free of flaws, is the correct size, weight, grade and length specified by the mill manufacturing procedure specification (MPS), the API/ISO standard and/or the purchase agreement, and thus can be expected to meet the required performance properties. Several types of inspections and tests are conducted to check the quality of the finished product. Mechanical testing consists of non destructive and destructive testing. Destructive testing requires that a sample of the steel from the finished product be removed to perform the tests. Verification of the outside diameter, wall thickness, length and straightness are non-destructive mechanical tests. Tables 20.3 and 20.4 list the tolerances for these variables. EPT Drilling
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Table 20.2. Chemical Requirements (by Percentage of Weight, API Specification 5CT or ISO 11960 [10]) Grp
Gde
Type
Carbon
Ni
Cu
P
S
Sl
Max
Max
Max
Max
Max
H40
0.030
0.030
J55
0.030
0.030
K55
0.030
0.030
Min 1
2
Manganese Max
Min
Max
Molybdenum Min
Max
Chromium Min
Max
N80
1
0.030
0.030
N80
Q
0.030
0.030
M65 L80
1
0.43a
L80
9Cr
0.15
0.30
0.60
L80
13Cr
0.22
0.25
1.00
C90
1
C90
2
0.015
1.90
0.35
1.20
0.90
1.10
0.25b
0.030
0.45
0.50
0.25
0.020
0.010
1.00
12.00
14.00
0.50
0.25
0.020
0.010
1.00
0.85
1.50
0.99
0.020
0.010
NL
NL
0.99
0.030
0.010
1.90 1.90
1
0.35
1.20
T95
2
0.50
1.90
3
P110
e
4
Q125
1
0.35
1.35
0.85
1.50
Q125
2
0.35
1.00
NL
NL
Q125
3
0.50
1.90
NL
Q125
4
0.50
1.90
NL
0.25d
0.030
10.00
0.50
T95
0.030
0.35
8.00
0.45c
C95
0.030 0.25
0.85
0.40
0.030
0.030
0.99
0.020
0.010
0.99
0.030
0.010
.030e
.030e
0.99
0.020
0.010
0.99
0.020
0.020
NL
0.99
0.030
0.010
NL
0.99
0.030
0.020
1.50
0.45
NL = No Limit. Elements shown must be reported in product analysis. a The carbon content for Grade L80 may be increased to 0.50 percent maximum if the product is oil quenched. b The molybdenum content for Grade C90, Type 1, has no minimum tolerance if the wall thickness is less than 0.700 in. c The carbon content for Grade C95 may be increased to 0.55 percent maximum if the product is oil quenched. d The molybdenum content for Grade T95, Type 1, may be decreased to 0.15 percent minimum if the wall thickness is less than 0.700 in. e The phosphorous is 0.020 percent maximum and the sulphur is 0.010 percent maximum for EW Grade P110.
Table 20.3. Dimensions and Tolerances (API Specification 5CT or ISO 11960 [10]) Outside Diameter (D)
Wall
Weight Min
Straightness
Min
Max
Min
Label 1 < 4.500
-0.031 in
+0.031in
-12.5%
0.2% of Length
Label 1 > 4.500
-0.5% of D
1.00%
-12.5%
0.2% of Length
Single length
-3.5%
Order items > 18,444 kg
-1.75%
Max
+6.5%
(40,000 lbs) Carload < 18,444 kg
-3.5%
(40,000 lbs)
20.6.1
Range
Table 20.4 lists range lengths for tubing and casing. All casing should be ordered as Range 3. All tubing should be ordered as Range 2 or Range 3 based on rig capability. The increased length is seldom difficult to handle, and choosing a longer average length EPT Drilling
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Table 20.4. Range Lengths (API Specification 5CT or ISO 11960 [10]) Range 1
2
3
Casing
Tubing
Integral Tubing
16 to 25 ft.
20 to 24 ft.
20 to 26 ft.
4.88 to 7.62 m
6.10 to 7.32 m
6.10 to 7.92 m
25 to 34 ft.
28 to 32 ft.
28 to 34 ft.
7.62 to 10.36 m
8.53 to 9.75 m
8.53 to 10.36 m
34 to 48 ft.
38 to 42 ft.
38 to 45 ft.
10.36 to 14.63 m
11.58 to 12.80 m
11.58 to 13.72 m
reduces the number of threaded connections in a string, thus reducing both cost and the probability of a connection leak or failure.
20.6.2
Drift Diameter
Drift diameter is an assured inside diameter. As a minimum, the drift diameter as defined in Table C/E.31 of API Specification 5CT or ISO 11960 [10] should be ordered. 20.6.2.1
Exceptions
Certain popular weights of casing have alternate drift diameters that, although recognized by the API (Table C/E.32 of API Specification 5CT or ISO 11960 [10]), must still be specified on the purchase agreement. A complete list of these special products is given in Table 20.5.
20.6.3
Hydrostatic Test
Hydrostatic testing is performed by the manufacturer on each finished pipe to a pressure of 20.68 MPa (3,000 psi) or 80% of minimum yield stress, whichever is less, regardless of grade or to a 69.0 MPa (10,000 psi) maximum. To obtain a higher test pressure, specify testing to the alternate hydrostatic test pressure when ordering material. Tables C/E. 45 through 61 in API Specification 5CT or ISO 11960 [10] have the standard and alternate hydrostatic test pressures for each size, weight and grade of casing and tubing. The alternate hydrostatic pressure is calculated with the same formula used by API TR 5C3 or ISO TR 10400 [9] to calculate the internal yield (burst) rating. pht = kht
2fym t . D
(20.1)
The value of kht for calculating the internal yield rating is 0.875. The value of kht for calculating the alternative hydrostatic test pressure is 0.800 (except for Grades H40, J55, and K55 in sizes larger than Label 1 9-5/8 which is 0.600). In other words, the alternate test pressure is 91.4% (0.800 divided by 0.875) of the minimum internal yield rating. EPT Drilling
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Table 20.5. Alternate Drift Diameters (API Specification 5CT or ISO 11960 [10]) Label 1
Outside Diameter
Mandrel Length
Mandrel Diameter
mm (in)
mm (in)
mm (in)
7
23.0
177.8 (7.000)
152 (6)
158.75 (6.250)
7
32.0
177.8 (7.000)
152 (6)
152.40 (6.000)
7-5/8a
52.8
193.7 (7.625)
152 (6)
155.58 (6.125)
7-3/4
46.1
196.9 (7.750)
152 (6)
165.10 (6.500)
8-5/8
32.0
219.1 (8.625)
152 (6)
200.02 (7.875)
8-5/8
40.0
219.1 (8.625)
152 (6)
193.68 (7.625)
9-5/8
40.0
244.5 (9.625)
305 (12)
222.25 (8.750)
9-5/8
53.5
244.5 (9.625)
305 (12)
215.90 (8.500)
9-5/8
58.4
244.5 (9.625)
305 (12)
212.72 (8.375)
a
62.8
250.8 (9.875)
305 (12)
215.90 (8.500)
10-3/4
45.5
273.1 (10.750)
305 (12)
250.82 (9.875)
10-3/4
55.5
273.1 (10.750)
305 (12)
244.48 (9.625)
11-3/4
42.0
298.5 (11.750)
305 (12)
279.40 (11.000)
11-3/4
60.0
298.5 (11.750)
305 (12)
269.88 (10.625)
11-3/4
65.0
298.5 (11.750)
305 (12)
269.88 (10.625)
13-3/8
72.0
339.7 (13.375)
305 (12)
311.15 (12.250)
13-5/8a
88.2
346.1 (13.625)
305 (12)
311.15 (12.250)
9-7/8
a
Weight
Not currently recognized by API as a valid alternate drift diameter.
20.6.4
Mechanical Properties
From a sample removed from the finished product, the chemical composition is analyzed and reported. Other important mechanical properties of the steel determined from the sample are the yield and tensile strengths and the hardness. These requirements are listed in Table 20.6. Also of importance are the elongation, the toughness, the grain size and the SSC resistance. The frequency of sampling and the specified minimum and maximum values and tolerances vary between grades and/or sizes and are usually considered the minimum acceptable. The hardness value is specified only for the Group 2 grades that are designed to be used in a potential sour gas environment. Generally, the lower the hardness value, the more resistant the steel to SSC. Sometimes when the grade of a pipe cannot be easily determined from the markings on the pipe, or the markings are in question, a surface hardness test is used in an attempt to identify the grade. This can be misleading, EPT Drilling
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Table 20.6. Grade Mechanical Properties Grade
Minimum Yield
Maximum Yield
Minimum Tensile
Maximum Hardness
a
(MPa/ksi)
(MPa/ksi)
(MPa/ksi)
(HRC)
H40
276/40
552/80
414/60
–
J55
379/55
552/80
517/75
–
K55
379/55
552/80
655/95
–
N80
552/80
758/110
689/100
–
M65
448/65
586/85
586/85
22
L80
552/80
655/95
655/95
23
C90
621/90
724/105
689/100
25.4
C95
655/95
758/110
724/105
–
T95
655/95
758/110
724/105
25.4
C110
758/110
827/120a
793/115
30a
P110
758/110
965/140
862/125
–
Q125
862/125
1034/150
931/135
–
B
241/35
–
413/60
–
X52
358/52
–
455/66
–
X56
386/56
–
489/71
–
X60
413/60
–
517/75
–
X80
551/80
–
620/90
–
These values were developed by BP and may not be used by other operators.
as hardness correlates better with tensile strength than yield strength, and so does not reliably determine grade. Elongation is a measure of ductility. Elongation is typically inversely proportional to the tensile strength. The higher grades, therefore, have lower elongation requirements. The minimum elongation in a 2 in. specimen is determined from the following formula: εel = 625, 000
0.2 Asp . 0.9 fumn
(20.2)
Toughness is a measure of resistance to crack propagation and is proportional to the impact energy measured by the Charpy V-Notch Impact Test. The value is measured in ft-lbs (Joules); the higher the value, the better the toughness. Minimums based on grade and size of sample are listed in API Specification EPT Drilling
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Table 20.7. Pipe Body Inspection Methods Grade
Visual
Wall Thickness Determination
UT
Flux Leakage Inspection
Eddy Current Inspection
H40, J55, K55, N80 Type 1
R
N
N
N
N
N
N80Q, L80, C95, M65
R
R
A
A
A
A
P110
R
R
B
C90, T95, Q125
R
C
B
B
C
Magnetic Particle Inspectiona
B B
Coupling stock H40, J55, K55, N80 Type 1
R
NA
N
N
N
N
Coupling stock N80Q, L80, C95, P110, C90, T95, Q125
R
R
A
A
A
A
R = required N = not required A = one method or any combination of methods shall be used B = at least one method (excluding the visual method) shall be used in addition to UT to inspect the outside surface C = UT shall be used to inspect the inside and outside surface NA = not applicable a MPI is permitted for end-area inspection. MPI is permitted for pipe-body outside-surface inspection in combination with other methods of pipe body inspection. MPI is permitted for coupling stock outside surface inspection. Coupling stock receiving full length MPI does not require full length wall thickness determination; however, mechanical wall thickness measurement of each end is required.
5CT or ISO 11960 [10]. Most steel manufactured currently can easily meet the API toughness requirements. Minimum energy requirements greater than ISO/API are required for most grades by BP specifications.
20.6.5
Flaw Inspection
Inspection of pipe is required to find imperfections or flaws in the pipe body created during the manufacturing process. Pipe body flaws are discontinuities or irregularities that are only created during the manufacturing process and include cracks, seams, laps, plug scores, cuts, gouges and pits. These flaws can be linear or non-linear and can occur in any orientation–longitudinal, transverse or oblique. The methods employed to detect flaws are visual, magnetic particle inspection (MPI), electromagnetic inspection (EMI) and ultrasonic (UT). The inspection methods for each grade, as required by API Specification 5CT or ISO 11960 [10], are listed in Table 20.7. When flaws are detected, they must be ground out completely, and the remaining pipe body wall thickness, under the flaw, must be 87.5% or more of the original specified wall thickness. UT and EMI equipment must use reference standards containing notches and/or holes to verify system response. The depths of the reference standards are usually either L2 (5%), L3 (10%), or L4 (12.5%) of specified pipe body wall and must be on the same diameter and wall thickness pipe as that to be inspected. The specific reference standard requirements for each grade are listed in Table 20.8. Grades H40, J55, K55 and N80 Type 1 are not included in Table 20.8. This is because API Specification 5CT or ISO 11960 [10] only requires a visual inspection for pipe body flaws in these grades. If additional inspection is desired it should be specified on the purchase agreement and should include type of inspection (EMI, UT, MPI), the standardization notch orientation (ID, OD, Longitudinal, Transverse) and the notch size (L2, L3, L4). EMI and UT type inspections are valid when the equipment is properly calibrated and standardized, but because both use wave theory (EMI is magnetic, and UT is sound.) for detection purposes, another EPT Drilling
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Table 20.8. Acceptance (Inspection) Levels Grade
External Imperfection
Internal Imperfection
Longitudinal
Transverse
Longitudinal
Transverse
M65, N80Q, L80, C95
L4
-
L4
-
P110 to A.9 (SR16)
L4
L4
L4
L4
P110
L2
L2
L2
L2
P110 to A.9 (SR16) and A.2 (SR2)
L2
L2
L2
L2
UT
L2
L2
L2
L2
Method
L2
L2
-
-
P110, Q125
L2
N
L2
N
All other grades
L3
N
L3
N
C90, T95, Q125 2
nd
N = not required Lx = acceptance (inspection) level inspection is often required to check the entire length of the pipe. The end area (EA) or special end area (SEA) inspection is necessary because of wave leakage near the ends of the pipe using EMI or UT inspection equipment. The length of the end area needing to be checked varies from 150 to 450 mm (6 to 18 in.) depending on the equipment and the size of the pipe. Some mills simply cut the end area off to eliminate the requirement. Those that perform the inspection typically use MPI. The difference between EA and SEA is that an SEA is performed on threaded pipe and usually includes some type of thread dimensional check. The EA or SEA inspection should ideally be performed after threading and before coupling installation.
20.7
Couplings
Couplings must be of the same grade and type and given the same heat treatment as the pipe on which they are to be installed. (There are several alternatives/exceptions in API Specification 5CT or ISO 11960 Clause 9 [10].) Most couplings are cut from “mother” tubes manufactured, tested and inspected in a manner similar to seamless OCTG. EW couplings are not allowed. Couplings may also be manufactured from forgings Groups 1, 2 and 3. Finished couplings, which include machining, require a wet fluorescent MPI for acceptance before installation.
20.8
Marking, Coating and Thread Protection
All pipe should be marked for easy identification. The guidelines and requirements of API Specification 5CT or ISO 11960 Clause 11 [10] should be followed. Note that even when the manufacturer meets API EPT Drilling
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specifications, it is not required to apply the API monogram to the product. As a minimum, all pipe purchased for downhole use should meet API Specification 5CT or ISO 11960 [10] requirements, and the application of the monogram should be required when placing a purchase request. The manufacturer will apply an external coating to finished tubulars to protect them from rust while in transit. This coating is usually good for 3 to 6 months in an average environment. If pipe may be stored for longer periods or in a harsh environment, steps should be taken to apply a more corrosion-resistant coating to the pipe. Thread protectors with the appropriate thread compound should be installed on all threaded pipe whenever it is being moved and when in storage. API Modified thread compound is not considered a corrosion resistant compound and should not be depended upon to protect threaded connections from corrosion for more than 2 to 3 months in an average environment. Storage compounds and several of the newer environmentally friendly thread compounds provide better corrosion resistance and should be considered for use under thread protectors. BP requirements for thread protectors and storage compounds are available in GIS 02-201 (Revision 3) Specification for OCTG Seamless Casing and Tubing [ISO 11960 & API Spec 5CT] [62], GIS 02-202 (Revision 1) Specification for OCTG EW Casing [ISO 11960 & API Spec 5CT] [63], GIS 02-204 (Revision 3) Specification for Sour Service Grades C110 and C125 Low Alloy Steel OCTG Seamless Pipe [61] and GIS 02-206 (Revision 9) Specification for Duplex and Super Duplex 25% Chrome Stainless Steel Seamless Pipe [65].
20.9
Pipe Inventory
See the following pages for the standard BP pipe inventory.
20.9.1
Standard Inventory Pipe and Connections
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Table 20.9. Size (Label 1) 2-3/8 Label 2
Wall
4.70
0.190
5.95
0.254
J55
N/L80/
C/T95/
L8013Cr
S13Cr95
2
4
4
3
4
4
1
P110
Available Connections Class
Integral
T&C
1
None
EUE
2
511, 501, 531,
561, SLHT
551 3
FJL, STL, 503
Bear, Blue
533, 553 4
2-Step, 8 Pitch
563, TOP
2-Step, 4 or 6 Pitch Table 20.10. Size (Label 1) 2-7/8 Label 2
Wall
J55
N/L80/ L8013Cr
C/T95/ S13Cr95
P110
6.50
0.217
1
2
7.90
0.276
3
4
4
8.70
0.308
3
4
4
Available Connections Class
Integral
T&C
1
None
EUE
2
511, 501, 531,
561, SLHT
551 3
FJL, SLF, STL,
Bear, Blue
503, 533, 553 4
2-Step, 8 Pitch
563, TOP
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Table 20.11. Size (Label 1) 3-1/2 Label 2
Wall
9.30
0.254
12.95
0.375
J55
N/L80/
C/T95/
L8013Cr
S13Cr95
1
P110
2 3
4
4
Available Connections Class
Integral
T&C
1
None
EUE
2
511, 501, 531,
561, SLHT
551 3
FJL, SLF, STL,
Bear, Blue
503, 533, 553 4
2-Step, 8 Pitch
563, TOP
2-Step, 4 or 6 Pitch Table 20.12. Size (Label 1) 4 Label 2
Wall
J55
N/L80/ L8013Cr
C/T95/ S13Cr95
P110
11.60
0.286
1
2
13.20
0.330
3
4
4
14.80
0.380
4
4
4
Available Connections Class
Integral
T&C
1
None
EUE
2
511, 521, 501,
561, SLHT
531, 551 3
FJL, SLF, STL,
Bear, Blue
503, 533, 553 4
2-Step, 8 Pitch
563, TOP
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Table 20.13. Size (Label 1) 4-1/2 Label 2
Wall
J/K55
N/L80/
C/T95/
L8013Cr
S13Cr95
C110
P110
11.60
0.250
1
12.75
0.271
1
13.50
0.290
3
3
4
15.50
0.337
3
3
4
17.00
0.380
3
4
4
4
19.20
0.430
4
4
4
4
Q125
2
4
Available Connections Class
Integral
T&C
1
None
BTC, LTC, EUE
2
511, 521, 501,
561, SLHT
531, 551 3
513, FJL, SLF
Bear, Blue
STL, 503, 533, 553 4
SLSF, ANJO, SLX
SLHC, 563, TOP
2-Step, 8 Pitch 2-Step, 4 or 6 Pitch
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Table 20.14. Size (Label 1) 5 Label 2
Wall
K55
N/L80/
HC95
L8013Cr 15.00
0.296
1
18.00
0.362
3
23.20
0.478
4
C/T95/
C110
P110
Q125
3
4
4
4
4
4
4
4
S13Cr95
2 3
Available Connections Class
Integral
T&C
1
None
BTC, LTC
2
511, 521
SLHT
3
513, FJL, SLF
Bear, TC-II, Blue,
STL, 533, 553
HW-ST
SLIJ II, SLSF, ANJO,
SLHC, 563, TOP,
SLX, 2-Step, 8 Pitch
TOP KP, TOP HT, TOP HC
4
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Table 20.15. Size (Label 1) 5-1/2 Label 2
Wall
K55
N/L80/
HC95
L8013Cr 15.50
0.275
1
17.00
0.304
1
20.00 23.00
C/T95/
C110
P110
Q125
S13Cr95
2
3
3
3
3
0.361
3
3
3
3
4
0.415
3
3
4
4
4
Available Connections Class
Integral
T&C
1
None
BTC, LTC
2
511, 521
SLHT
3
513, FJL, SLF
Bear, TC-II, Blue,
STL, 533, 553
HW-ST
SLIJ II, SLSF, ANJO,
SLHC, 563, TOP,
SLX, MAC II,
TOP KP, TOP HT, TOP HC
4
2-Step, 8 Pitch
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Table 20.16. Size (Label 1) 7 Label 2
Wall
K55
N/L80/
HC95
L8013Cr
C/T95/
C110
P110
Q125
3
3
3
3
4
4
4
4
4
S13Cr95
23.00
0.317
1
26.00
0.362
1
29.00
0.408
2
32.00
0.453
2
35.00
0.498
3
4
38.00
0.540
4
4
41.00
0.590
4
4
1 2
Available Connections Class
Integral
T&C
1
None
BTC, LTC
2
511, 521
SLHT, ATS-E
3
513, 523, FJL,
Bear, TC-II, Blue,
SLF, STL, 533,
HW-ST
553 4
SLIJ II, SLSF, ANJO,
SLHC, 563, TOP,
SLX, MAC II,
TOP KP, TOP HT, TOP HC
2-Step, 8 Pitch
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Table 20.17. Size (Label 1) 7-5/8 Label 2
Wall
N/L80/
HC95
C/T95/
L8013Cr
C110
P110
Q125
S13Cr95
26.40
0.328
1
29.70
0.375
1
3
3
33.70
0.430
2
2
3
3
3
39.00
0.500
3
4
4
4
45.30
0.595
4
4
47.10
0.625
4
4
4
4
52.80
0.712
4
4
55.30
0.750
4
4
Available Connections Class
Integral
T&C
1
None
BTC, LTC
2
511, 521
BOSS, ATS-E
3
513, 523, FJL,
Bear, TC-II, Blue,
SLF, STL, 533,
HW-ST
553 4
EPT Drilling
SLIJ II, SLSF, ANJO,
SLHC, 563, TOP,
SLX, MAC II
TOP KP, TOP HC
368
BP Confidential
Table 20.18. Size (Label 1) 7-3/4 Label 2
Wall
46.10
0.595
N/L80
HC95
T95
C110
P110
Q125
4
4
4
4
Available Connections Class
Integral
T&C
1
None
BTC, LTC
2
511, 521
BOSS, ATS-E
3
513, 523
Bear, TC-II, Blue, HW-ST
4
SLIJ II, SLSF, ANJO,
SLHC, 563, TOP,
SLX, MAC II
TOP HC
Table 20.19. Size (Label 1) 8-5/8 Label 2
Wall
K55
24.00
0.264
1
32.00
0.352
1
54.00 63.50
N/L80
HC95
T95
C110
0.625
3
4
0.750
4
4
Available Connections Class
Integral
T&C
1
None
BTC, LTC
2
511, 521
BOSS, ATS-E
3
513, 523
Bear, TC-II, Blue, HW-ST
4
SLIJ II, SLSF, ANJO,
SLHC, 563, TOP
SLX, MAC II
EPT Drilling
369
BP Confidential
Table 20.20. Size (Label 1) 9-5/8 Label 2
Wall
K55
N/L80
HC95
T95
C110
P110
36.00
0.352
1
40.00
0.395
1
43.50
0.435
1
2
2
3
3
47.00
0.472
2
2
3
3
3
53.50
0.545
2
2
3
3
3
Q125
4
Available Connections Class
Integral
T&C
1
None
BTC, LTC
2
511, 521
BOSS, DINO VAM, ATS-E
3
513, 523
Bear, TC-II, Blue, HW-ST
4
SLIJ II, SLSF, ANJO,
SLHC, 563, TOP
SLX, MAC II
Table 20.21. Size (Label 1) 9-7/8 Label 2
Wall
62.80
0.625
K55
N/L80
HC95
T95
C110
P110
Q125
3
4
4
4
Available Connections Class
Integral
T&C
1
None
BTC
2
511, 521
BOSS, DINO VAM, ATS-E
3
513, 523
TC-II, Blue, HW-ST
4
SLIJ II, SLSF, ANJO,
SLHC, 563, TOP
SLX, MAC II
EPT Drilling
370
BP Confidential
Table 20.22. Size (Label 1) 10 Label 2
Wall
68.49
0.688
K55
N/L80
HC95
T95
C110
3
4
P110
Q125 4
Available Connections Class
Integral
T&C
1
None
BTC
2
511, 521
BOSS, DINO VAM, ATS-E
3
513, 523
TC-II, Blue, HW-ST
4
SLIJ II, SLSF, ANJO,
SLHC, 563, TOP
SLX, MAC II
Table 20.23. Size (Label 1) 10-3/4 Label 2
Wall
K55
40.50
0.350
1
45.50
0.400
1
60.70
N/L80
HC95
T95
C110
0.545
2
3
65.70
0.595
3
3
71.10
0.650
3
3
80.80
0.750
3
4
91.20
0.859
4
4
102.90
0.984
4
4
1
P110
Q125
4
Available Connections Class
Integral
T&C
1
None
BTC
2
511, 521
BOSS, DINO VAM, ATS-E
3
513, 523
TC-II, Blue, HW-ST
4
SLIJ II, SLSF, ANJO,
SLHC, 563, TOP
SLX, MAC II
EPT Drilling
371
BP Confidential
Table 20.24. Size (Label 1) 11-3/4 Label 2
Wall
65.00 71.00
K55
N/L80
HC95
T95
C110
P110
Q125
0.534
2
3
3
3
0.582
3
3
Available Connections Class
Integral
T&C
1
None
BTC
2
511, 521
BOSS, DINO VAM, ATS-E
3
513, 523
TC-II, Blue, HW-ST
4
SLIJ II, SLSF, ANJO,
SLHC, 563, TOP
SLX, MAC II
Table 20.25. Size (Label 1) 11-7/8 Label 2
Wall
71.80
0.582
K55
N/L80
HC95
T95
C110
P110
Q125
3
4
4
4
Available Connections Class
Integral
T&C
1
None
BTC
2
511, 521
BOSS, DINO VAM, ATS-E
3
513, 523
TC-II, Blue, HW-ST
4
SLIJ II, SLSF, ANJO,
SLHC, 563, TOP
SLX, MAC II
EPT Drilling
372
BP Confidential
Table 20.26. Size (Label 1) 13-3/8 Label 2
Wall
K55
61.00
0.430
1
68.00
0.480
1
72.00
0.514
N/L80
HC95
T95
P110
Q125
2
2
3
3
2 2
Available Connections Class
Integral
T&C
1
None
BTC
2
521
BOSS, DINO VAM, ATS-E
3
513, 523
TC-II, Blue, HW-ST
4
SLIJ II, SLSF, ANJO,
SLHC, 563, TOP
SLX, MAC II
EPT Drilling
373
BP Confidential
Table 20.27. Size (Label 1) 13-5/8 Label 2
Wall
88.20
0.625
K55
N/L80
HC95
T95
P110
Q125
2
3
3
Available Connections Class
Integral
T&C
1
None
None
2
521
BOSS, DINO VAM, ATS-E
3
513, 523
Blue, HW-ST
4
SLIJ II, SLSF, ANJO,
SLHC, 563, TOP
SLX, MAC II
Table 20.28. Size (Label 1) 16 Label 2
Wall
K55
65.00
0.375
1
84.00
0.495
1
96.00
0.575
109.00
0.656
N/L80
HC95
T95
P110
Q125
2
3
2
2 Available Connections
Class
Integral
T&C
1
None
None
2
511, 521
BOSS, DINO VAM, ATS-E GB-3P
EPT Drilling
3
513, 523
None
4
MAC II
563
374
BP Confidential
Table 20.29. Size (Label 1) 18 Label 2
Wall
116.09
0.625
K55
N/L80
HC95
T95
P110
Q125
2 Available Connections
Class
Integral
T&C
1
None
None
2
511, 521
BOSS, ATS-E, GB-3P
3
None
None
4
None
None
Table 20.30. Size (Label 1) 18-5/8 Label 2
Wall
K55
N/L80
87.50
0.435
1
1
97.70
0.486
1
1
109.30
0.563
2
139.00
0.720
2
Available Connections
EPT Drilling
Class
Integral
T&C
1
None
None
2
511, 521
BOSS, ATS-E, GB-3P
3
None
None
4
None
None
375
BP Confidential
Table 20.31. Size (Label 1) 20 Label 2
Wall
H40
X52
K55
X56
94.00
0.438
1
106.50
0.500
1
1
1
129.30
0.625
1
133.00
0.635
166.40
0.812
1
N80
X80
1
1
1 1
1
Available Connections Class
Integral
T&C
Weld On
1
None
None
ALT-2, QUIK-STAB, QUIK-JAY, LYNX, MERLIN, RL-4, RL-1, DQ QT/MT, LEOPARD SD, SWIFT DW2, VIPER
2
EPT Drilling
XLF, XLF-RB,
BOSS, ATS-E,
XLCS, XLCS-RB
GB-3P
3
None
None
None
4
None
None
None
376
XLW
BP Confidential
Table 20.32. Size (Label 1) 22 Label 2
Wall
H40
X52
K55
X56
N80
X80
170.37
0.750
1
1
1
224.49
1.000
1
1
1
Available Connections Class
Integral
T&C
Weld On
1
None
None
ALT-2, QUIK-STAB, QUIK-JAY, LYNX, MERLIN, RL-4, RL-1, DQ QT/MT, LEOPARD SD, SWIFT DW2, VIPER
2
XLF, XLF-RB,
None
XLW
XLCS, XLCS-RB
EPT Drilling
3
None
None
None
4
None
None
None
377
BP Confidential
Table 20.33. Size (Label 1) 24 Label 2
Wall
H40
X52
K55
X56
156.17
0.625
1
1
186.41
0.750
1
1
201.28
0.812
1
1
N80
X80
Available Connections Class
Integral
T&C
Weld On
1
None
None
ALT-2, QUIK-STAB, QUIK-JAY, LYNX, MERLIN, RL-4, RL-1, DQ QT/MT, LEOPARD SD, SWIFT DW2, VIPER
2
XLF, XLF-RB,
None
XLW
XLCS, XLCS-RB
EPT Drilling
3
None
None
None
4
None
None
None
378
BP Confidential
Table 20.34. Size (Label 1) 26 Label 2
Wall
116.54
0.625
H40
X52
K55
X56
2
N80
2
X80 1
Available Connections Class
Integral
T&C
Weld On
1
None
None
ALT-2, QUIK-STAB, QUIK-JAY, LYNX, MERLIN, RL-4, RL-1, DQ QT/MT, LEOPARD SD, SWIFT DW2, VIPER
2
XLF, XLF-RB,
None
XLW
XLCS, XLCS-RB 3
None
None
None
4
None
None
None
Table 20.35. Size (Label 1) 28 Label 2
Wall
218.48
0.750
B
X52
K55
X56
N80
X80
2 Available Connections
Class
Integral
T&C
Weld On
1
None
None
ALT-2, QUIK-STAB, QUIK-JAY, LYNX, MERLIN, RL-4, RL-1, DQ QT/MT, LEOPARD SD, SWIFT DW2, VIPER
2
XLF, XLF-RB,
None
XLW
XLCS, XLCS-RB
EPT Drilling
3
None
None
None
4
None
None
None
379
BP Confidential
Table 20.36. Size (Label 1) 30 Label 2
Wall
B
X52
K55
X56
310.01
1.000
1
1
1
457.00
1.500
1
1
1
N80
X80
Available Connections Class
Integral
T&C
Weld On
1
None
None
ALT-2, ST-2, QUIK-STAB, QUIK-JAY, LYNX, MERLIN, RL-4, RL-1, DQ QT/MT, LEOPARD SD, SWIFT DW2, VIPER
2
XLF, XLF-RB,
None
XLW
XLCS, XLCS-RB
EPT Drilling
3
None
None
None
4
None
None
None
380
BP Confidential
Table 20.37. Size (Label 1) 36 Label 2
Wall
B
X52
K55
X56
373.80
1.000
1
1
1
552.70
1.500
1
1
1
726.24
2.000
1
1
1
N80
X80
Available Connections Class
Integral
T&C
Weld On
1
None
None
ALT-2, QUIK-STAB, QUIK-JAY, LYNX, MERLIN, RL-4, RL-1, DQ QT/MT, LEOPARD SD, SWIFT DW2, VIPER
2
XLF, XLF-RB,
None
XLW
XLCS, XLCS-RB
EPT Drilling
3
None
None
None
4
None
None
None
381
BP Confidential
Table 20.38. Standard Inventory Pipe Performance Properties Wall
ID
Drift Dia-
Burst
Collapse
Axial
Label 1
Label 2
Grade
(in)
(in)
meter (in)
(psi)
(psi)
(lbf)
2.375
4.70
J55
0.190
1.995
1.870
7700
8096
71733
2.375 2.375
4.70 4.70
L80 N80
0.190 0.190
1.995 1.995
1.870 1.870
11200 11200
11776 11776
104339 104339
2.375 2.375
4.70 4.70
T95 P110
0.190 0.190
1.995 1.995
1.870 1.870
13300 15400
13984 16129
123902 143466
2.375 2.375
5.95 5.95
L80 N80
0.254 0.254
1.867 1.867
1.742 1.742
14973 14973
15282 15282
135399 135399
2.375 2.375
5.95 5.95
T95 P110
0.254 0.254
1.867 1.867
1.742 1.742
17780 20587
18147 21012
160786 186173
2.875
6.50
J55
0.217
2.441
2.316
7265
7676
99661
2.875 2.875
6.50 6.50
L80 N80
0.217 0.217
2.441 2.441
2.316 2.316
10567 10567
11165 11165
144962 144962
2.875 2.875
7.90 7.90
L80 N80
0.276 0.276
2.323 2.323
2.198 2.198
13440 13440
13885 13885
180283 180283
2.875
7.90
T95
0.276
2.323
2.198
15960
16489
214086
2.875 2.875
7.90 8.70
P110 L80
0.276 0.308
2.323 2.259
2.198 2.134
18480 14998
19092 15305
247889 198708
2.875 2.875
8.70 8.70
N80 T95
0.308 0.308
2.259 2.259
2.134 2.134
14998 17810
15305 18174
198708 235966
2.875
8.70
P110
0.308
2.259
2.134
20623
21044
273224
3.500 3.500
9.30 9.30
J55 L80
0.254 0.254
2.992 2.992
2.867 2.867
6985 10160
7404 10535
142461 207215
3.500 3.500
9.30 12.95
N80 L80
0.254 0.375
2.992 2.750
2.867 2.625
10160 15000
10535 15306
207215 294524
3.500 3.500
12.95 12.95
N80 T95
0.375 0.375
2.750 2.750
2.625 2.625
15000 17813
15306 18176
294524 349748
3.500
12.95
P110
0.375
2.750
2.625
20625
21046
404971
4.000
11.60
J55
0.286
3.428
3.303
6882
7303
183536
4.000 4.000
11.60 11.60
L80 N80
0.286 0.286
3.428 3.428
3.303 3.303
10010 10010
10272 10272
266961 266961
4.000
13.20
L80
0.330
3.340
3.215
11550
12111
304383
Continued on next page EPT Drilling
382
BP Confidential
Wall
ID
Drift Dia-
Burst
Collapse
Axial
Label 1
Label 2
Grade
(in)
(in)
meter (in)
(psi)
(psi)
(lbf)
4.000 4.000
13.20 13.20
N80 T95
0.330 0.330
3.340 3.340
3.215 3.215
11550 13716
12111 14382
304383 361454
4.000 4.000
13.20 14.80
P110 L80
0.330 0.380
3.340 3.240
3.215 3.115
15881 13300
16653 13756
418526 345726
4.000 4.000
14.80 14.80
N80 T95
0.380 0.380
3.240 3.240
3.115 3.115
13300 15794
13756 16335
345726 410550
4.000
14.80
P110
0.380
3.240
3.115
18287
18914
475373
4.500
11.60
J55
0.250
4.000
3.875
5347
4958
183587
4.500 4.500
11.60 12.75
K55 J55
0.250 0.271
4.000 3.958
3.875 3.833
5347 5796
4958 5725
183587 198025
4.500 4.500
12.75 12.75
K55 L80
0.271 0.271
3.958 3.958
3.833 3.833
5796 8431
5725 7501
198025 288036
4.500 4.500
12.75 13.50
N80 L80
0.271 0.290
3.958 3.920
3.833 3.841
8431 9022
7501 8539
288036 306846
4.500 4.500
13.50 13.50
N80 T95
0.290 0.290
3.920 3.920
3.841 3.841
9022 10714
8539 9665
306846 364379
4.500 4.500
13.50 15.50
C110 L80
0.290 0.337
3.920 3.826
3.841 3.701
12406 10484
10686 11085
421913 352595
4.500 4.500
15.50 15.50
N80 T95
0.337 0.337
3.826 3.826
3.701 3.701
10484 12450
11085 12765
352595 418707
4.500
15.50
C110
0.337
3.826
3.701
14416
14341
484818
4.500 4.500
17.00 17.00
L80 N80
0.380 0.380
3.740 3.740
3.615 3.615
11822 11822
12370 12370
393478 393478
4.500 4.500
17.00 17.00
T95 C110
0.380 0.380
3.740 3.740
3.615 3.615
14039 16256
14690 17009
467255 541033
4.500 4.500
17.00 19.20
P110 L80
0.380 0.430
3.740 3.640
3.615 3.515
16256 13378
17009 13828
541033 439848
4.500 4.500
19.20 19.20
N80 T95
0.430 0.430
3.640 3.640
3.515 3.515
13378 15886
13828 16421
439848 522320
4.500 4.500
19.20 19.20
C110 P110
0.430 0.430
3.640 3.640
3.515 3.515
18394 18394
19013 19013
604791 604791
4.500
19.20
Q125
0.430
3.640
3.515
20903
21606
687263
5.000 5.000
15.00 15.00
K55 L80
0.296 0.296
4.408 4.408
4.283 4.283
5698 8288
5557 7250
240587 349944
5.000
15.00
N80
0.296
4.408
4.283
8288
7250
349944
Continued on next page EPT Drilling
383
BP Confidential
Wall
ID
Drift Dia-
Burst
Collapse
Axial
Label 1
Label 2
Grade
(in)
(in)
meter (in)
(psi)
(psi)
(lbf)
5.000 5.000
18.00 18.00
L80 N80
0.362 0.362
4.276 4.276
4.151 4.151
10136 10136
10493 10493
421968 421968
5.000 5.000
18.00 18.00
C95 T95
0.362 0.362
4.276 4.276
4.151 4.151
12037 12037
12026 12026
501087 501087
5.000 5.000
18.00 18.00
C110 P110
0.362 0.362
4.276 4.276
4.151 4.151
13937 13937
13470 13470
580206 580206
5.000
18.00
Q125
0.362
4.276
4.151
15838
14823
659324
5.000 5.000
23.20 23.20
L80 N80
0.478 0.478
4.044 4.044
3.919 3.919
13384 13384
13834 13834
543248 543248
5.000 5.000
23.20 23.20
T95 C110
0.478 0.478
4.044 4.044
3.919 3.919
15894 18403
16428 19021
645107 746966
5.000 5.000
23.20 23.20
P110 Q125
0.478 0.478
4.044 4.044
3.919 3.919
18403 20913
19021 21615
746966 848825
5.500
15.50
K55
0.275
4.950
4.825
4812
4044
248274
5.500 5.500
17.00 17.00
K55 L80
0.304 0.304
4.892 4.892
4.767 4.767
5320 7738
4911 6285
272933 396993
5.500 5.500
17.00 17.00
N80 C95
0.304 0.304
4.892 4.892
4.767 4.767
7738 9189
6285 6942
396993 471429
5.500 5.500
17.00 17.00
T95 C110
0.304 0.304
4.892 4.892
4.767 4.767
9189 10640
6942 7477
471429 545865
5.500
17.00
P110
0.304
4.892
4.767
10640
7477
545865
5.500 5.500
20.00 20.00
L80 N80
0.361 0.361
4.778 4.778
4.699 4.699
9189 9189
8831 8831
466257 466257
5.500 5.500
20.00 20.00
C95 T95
0.361 0.361
4.778 4.778
4.699 4.699
10912 10912
10019 10019
553681 553681
5.500 5.500
20.00 20.00
C110 P110
0.361 0.361
4.778 4.778
4.699 4.699
12635 12635
11103 11103
641104 641104
5.500 5.500
23.00 23.00
L80 N80
0.415 0.415
4.670 4.670
4.591 4.591
10564 10564
11162 11162
530370 530370
5.500 5.500
23.00 23.00
T95 C110
0.415 0.415
4.670 4.670
4.591 4.591
12544 14525
12933 14539
629814 729259
5.500 5.500
23.00 23.00
P110 Q125
0.415 0.415
4.670 4.670
4.591 4.591
14525 16506
14539 16060
729259 828703
7.000
23.00
K55
0.317
6.366
6.250
4359
3269
366052
7.000
26.00
K55
0.362
6.276
6.151
4978
4326
415201
Continued on next page EPT Drilling
384
BP Confidential
Wall
ID
Drift Dia-
Burst
Collapse
Axial
Label 1
Label 2
Grade
(in)
(in)
meter (in)
(psi)
(psi)
(lbf)
7.000 7.000
26.00 26.00
L80 N80
0.362 0.362
6.276 6.276
6.151 6.151
7240 7240
5411 5411
603929 603929
7.000 7.000
29.00 29.00
L80 N80
0.408 0.408
6.184 6.184
6.059 6.059
8160 8160
7026 7026
675954 675954
7.000 7.000
29.00 29.00
C95 T95
0.408 0.408
6.184 6.184
6.059 6.059
9690 9690
7837 7837
802696 802696
7.000
29.00
C110
0.408
6.184
6.059
11220
8532
929437
7.000 7.000
29.00 32.00
Grade P110 L80
0.408 0.453
6.184 6.094
6.059 6.000
11220 9060
8532 8605
929437 745385
7.000 7.000
32.00 32.00
N80 T95
0.453 0.453
6.094 6.094
6.000 6.000
9060 10759
8605 9745
745385 885144
7.000 7.000
32.00 32.00
C110 P110
0.453 0.453
6.094 6.094
6.000 6.000
12457 12457
10781 10781
1024904 1024904
7.000 7.000
32.00 35.00
Q125 T95
0.453 0.498
6.094 6.004
6.000 5.879
14156 11828
11711 11653
1164663 966384
7.000 7.000
35.00 35.00
C110 P110
0.498 0.498
6.004 6.004
5.879 5.879
13695 13695
13030 13030
1118971 1118971
7.000 7.000
35.00 38.00
Q125 T95
0.498 0.540
6.004 5.920
5.879 5.875
15563 12825
14314 13434
1271558 1041118
7.000 7.000
38.00 41.00
C110 T95
0.540 0.590
5.920 5.820
5.875 5.695
14850 14012
15129 14665
1205504 1128713
7.000
41.00
C110
0.590
5.820
5.695
16225
16980
1306931
7.625
26.40
L80
0.328
6.969
6.844
6022
3403
601531
7.625 7.625
26.40 29.70
N80 L80
0.328 0.375
6.969 6.875
6.844 6.750
6022 6885
3403 4789
601531 683296
7.625 7.625
29.70 29.70
N80 C95
0.375 0.375
6.875 6.875
6.750 6.750
6885 8176
4789 5134
683296 811414
7.625 7.625
29.70 33.70
T95 L80
0.375 0.430
6.875 6.765
6.750 6.640
8176 7895
5134 6561
811414 777569
7.625 7.625
33.70 33.70
N80 C95
0.430 0.430
6.765 6.765
6.640 6.640
7895 9375
6561 7275
777569 923364
7.625 7.625
33.70 33.70
T95 C110
0.430 0.430
6.765 6.765
6.640 6.640
9375 10856
7275 7870
923364 1069158
7.625 7.625
33.70 39.00
P110 T95
0.430 0.500
6.765 6.625
6.640 6.500
10856 10902
7870 10000
1069158 1063233
7.625
39.00
C110
0.500
6.625
6.500
12623
11082
1231112
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Wall
ID
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Axial
Label 1
Label 2
Grade
(in)
(in)
meter (in)
(psi)
(psi)
(lbf)
7.625 7.625
39.00 39.00
P110 Q125
0.500 0.500
6.625 6.625
6.500 6.500
12623 14344
11082 12059
1231112 1398990
7.625 7.625
45.30 45.30
T95 C110
0.595 0.595
6.435 6.435
6.310 6.310
12973 15021
13669 15441
1248377 1445489
7.625 7.625
47.10 47.10
T95 C110
0.625 0.625
6.375 6.375
6.250 6.250
13627 15779
14297 16555
1305724 1511891
7.625
47.10
P110
0.625
6.375
6.250
15779
16555
1511891
7.625 7.625
47.10 52.80
Q125 T95
0.625 0.712
6.375 6.201
6.250 6.125
17930 15524
18696 16085
1718058 1468994
7.625 7.625
52.80 55.30
C110 T95
0.712 0.750
6.201 6.125
6.125 6.000
17975 16352
18625 16850
1700940 1538890
7.625
55.30
C110
0.750
6.125
6.000
18934
19511
1781872
7.750 7.750
46.10 46.10
T95 C110
0.595 0.595
6.560 6.560
6.500 6.500
12764 14779
13324 15000
1270574 1471191
7.750 7.750
46.10 46.10
P110 Q125
0.595 0.595
6.560 6.560
6.500 6.500
14779 16794
15000 16594
1471191 1671808
8.625
24.00
K55
0.264
8.097
7.972
2946
1371
381395
8.625 8.625
32.00 54.00
K55 T95
0.352 0.625
7.921 7.375
7.875 7.250
3928 12047
2533 12045
503174 1492257
8.625
54.00
C110
0.625
7.375
7.250
13949
13492
1727876
8.625 8.625
63.50 63.50
T95 C110
0.750 0.750
7.125 7.125
7.000 7.000
14457 16739
15085 17467
1762728 2041053
9.625
36.00
K55
0.352
8.921
8.765
3520
2024
563995
9.625 9.625
40.00 43.50
K55 L80
0.395 0.435
8.835 8.755
8.750 8.599
3950 6327
2570 3810
629958 1004719
9.625 9.625
43.50 43.50
N80 C95
0.435 0.435
8.755 8.755
8.599 8.599
6327 7514
3810 4127
1004719 1193104
9.625 9.625
43.50 43.50
T95 C110
0.435 0.435
8.755 8.755
8.599 8.599
7514 8700
4127 4420
1193104 1381489
9.625 9.625
43.50 47.00
P110 L80
0.435 0.472
8.755 8.681
8.599 8.525
8700 6865
4420 4754
1381489 1085789
9.625 9.625
47.00 47.00
N80 C95
0.472 0.472
8.681 8.681
8.525 8.525
6865 8153
4754 5092
1085789 1289374
9.625
47.00
T95
0.472
8.681
8.525
8153
5092
1289374
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Wall
ID
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Axial
Label 1
Label 2
Grade
(in)
(in)
meter (in)
(psi)
(psi)
(lbf)
9.625 9.625
47.00 47.00
C110 P110
0.472 0.472
8.681 8.681
8.525 8.525
9440 9440
5296 5296
1492959 1492959
9.625 9.625
53.50 53.50
L80 N80
0.545 0.545
8.535 8.535
8.500 8.500
7927 7927
6617 6617
1243719 1243719
9.625 9.625
53.50 53.50
C95 T95
0.545 0.545
8.535 8.535
8.500 8.500
9414 9414
7343 7343
1476916 1476916
9.625
53.50
C110
0.545
8.535
8.500
10900
7950
1710113
9.625 9.625
53.50 53.50
P110 Q125
0.545 0.545
8.535 8.535
8.500 8.500
10900 12386
7950 8436
1710113 1943311
9.875
62.80
T95
0.625
8.625
8.500
10522
9322
1725422
9.875 9.875
62.80 62.80
C110 P110
0.625 0.625
8.625 8.625
8.500 8.500
12184 12184
10283 10283
1997857 1997857
9.875
62.80
Q125
0.625
8.625
8.500
13845
11135
2270292
10.000 10.000
68.49 68.49
T95 C110
0.688 0.688
8.624 8.624
8.468 8.468
11438 13244
10958 12210
1912075 2213981
10.000
68.49
Q125
0.688
8.625
8.469
15039
13345
2514195
10.750 10.750
40.50 45.50
K55 K55
0.350 0.400
10.050 9.950
9.894 9.875
3134 3581
1585 2094
628947 715341
10.750
60.70
T95
0.545
9.660
9.581
8428
5585
1659904
10.750 10.750
60.70 65.70
C110 T95
0.545 0.595
9.660 9.560
9.581 9.500
9759 9202
5877 6965
1921994 1803310
10.750 10.750
65.70 71.10
C110 T95
0.595 0.650
9.560 9.450
9.500 9.294
10655 10052
7504 8484
2088043 1959333
10.750 10.750
71.10 80.80
C110 L80
0.650 0.750
9.450 9.250
9.294 9.094
11640 9767
9294 9846
2268701 1884956
10.750 10.750
80.80 80.80
N80 T95
0.750 0.750
9.250 9.250
9.094 9.094
9767 11599
9846 11245
1884956 2238385
10.750 10.750
80.80 91.20
C110 T95
0.750 0.859
9.250 9.032
9.094 8.876
13430 13285
12549 13969
2591814 2535752
10.750 10.750
91.20 102.90
C110 T95
0.859 0.984
9.032 8.782
8.876 8.626
15382 15218
16096 15800
2936134 2868041
10.750 10.750
102.90 102.90
C110 Q125
0.984 0.984
8.782 8.782
8.626 8.626
17620 20023
18294 20789
3320889 3773738
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Axial
Label 1
Label 2
Grade
(in)
(in)
meter (in)
(psi)
(psi)
(lbf)
11.750 11.750
65.00 65.00
T95 C110
0.534 0.534
10.682 10.682
10.625 10.625
7556 8749
4176 4477
1787528 2069769
11.750 11.750
65.00 65.00
P110 Q125
0.534 0.534
10.682 10.682
10.625 10.625
8749 9941
4477 4690
2069769 2352010
11.750 11.750
71.00 71.00
T95 C110
0.582 0.582
10.586 10.586
10.430 10.430
8235 9535
5239 5469
1939867 2246161
11.875 11.875
71.80 71.80
T95 C110
0.582 0.582
10.711 10.711
10.625 10.625
8148 9435
5084 5287
1961579 2271302
11.875 11.875
71.80 71.80
P110 Q125
0.582 0.582
10.711 10.711
10.625 10.625
9435 10721
5287 5628
2271302 2581025
13.375
61.00
K55
0.430
12.515
12.359
3094
1540
961796
13.375 13.375
68.00 68.00
K55 L80
0.480 0.480
12.415 12.415
12.259 12.259
3454 5024
1949 2264
1069486 1555616
13.375 13.375
68.00 72.00
N80 L80
0.480 0.514
12.415 12.347
12.259 12.250
5024 5380
2264 2670
1555616 1661413
13.375 13.375
72.00 72.00
N80 C95
0.514 0.514
12.347 12.347
12.250 12.250
5380 6389
2670 2823
1661413 1972928
13.375 13.375
72.00 72.00
T95 P110
0.514 0.514
12.347 12.347
12.250 12.250
6389 7398
2823 2882
1972928 2284443
13.375
72.00
Q125
0.514
12.347
12.250
8407
2883
2595958
13.625
88.20
L80
0.625
12.375
12.250
6422
3976
2042035
13.625 13.625
88.20 88.20
N80 T95
0.625 0.625
12.375 12.375
12.250 12.250
6422 7626
3976 4258
2042035 2424917
13.625 13.625
88.20 88.20
P110 Q125
0.625 0.625
12.375 12.375
12.250 12.250
8830 10034
4574 4802
2807798 3190680
16.000
65.00
K55
0.375
15.250
15.063
2256
634
1012427
16.000 16.000
84.00 84.00
K55 L80
0.495 0.495
15.010 15.010
14.823 14.823
2978 4331
1407 1481
1326140 1928932
16.000 16.000
84.00 96.00
N80 P110
0.495 0.575
15.010 14.850
14.823 14.663
4331 6918
1481 2345
1928932 3065036
16.000 16.000
96.00 109.00
Q125 L80
0.575 0.656
14.850 14.688
14.663 14.501
7861 5740
2345 3081
3482995 2529777
16.000
109.00
N80
0.656
14.688
14.501
5740
3081
2529777
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Label 1
Label 2
Grade
(in)
(in)
meter (in)
(psi)
(psi)
(lbf)
18.625
87.50
K55
0.435
17.755
17.567
2248
627
1367208
18.625 18.625
87.50 87.50
L80 N80
0.435 0.435
17.755 17.755
17.567 17.567
3270 3270
627 627
1988666 1988666
18.625 18.625
97.70 97.70
K55 L80
0.486 0.486
17.653 17.653
17.465 17.465
2512 3653
880 880
1523218 2215590
18.625
97.70
N80
0.486
17.653
17.465
3653
880
2215590
18.625 18.625
109.30 109.30
L80 N80
0.563 0.563
17.499 17.499
17.311 17.311
4232 4232
1379 1379
2555725 2555725
18.625 18.625
139.00 139.00
L80 N80
0.720 0.720
17.185 17.185
17.000 17.000
5412 5412
2706 2706
3240012 3240012
20.000
94.00
H40
0.438
19.124
18.936
1533
516
1076706
20.000 20.000
106.50 106.50
X52 K55
0.500 0.500
19.000 19.000
18.813 18.813
2275 2406
772 772
1592787 1684679
20.000 20.000
106.50 129.33
X56 X52
0.500 0.625
19.000 18.750
18.813 18.563
2450 2844
772 1415
1715310 1978222
20.000 20.000
129.33 133.00
X56 K55
0.625 0.635
18.750 18.730
18.563 18.543
3063 3056
1450 1496
2130393 2124730
20.000 20.000
133.00 166.40
X80 X80
0.635 0.812
18.730 18.376
18.543 18.189
4445 5684
1603 3017
3090517 3915846
20.000
166.40
N80
0.812
18.376
18.189
5684
3017
3915846
22.000
170.37
X52
0.750
20.500
20.313
3102
1710
2603595
22.000 22.000
170.37 170.37
X56 X80
0.750 0.750
20.500 20.500
20.313 20.313
3341 4773
1766 1976
2803871 4005531
22.000 22.000
224.49 224.49
X80 X52
1.000 1.000
20.000 20.000
19.813 19.813
6364 4136
3873 3199
5277876 3430619
22.000
224.49
X56
1.000
20.000
18.813
6682
7116
5409823
24.000 24.000
156.03 156.03
X52 X56
0.625 0.625
22.750 22.750
22.563 22.563
2370 2552
874 874
2386629 2570215
24.000 24.000
186.23 186.23
X52 X56
0.750 0.750
22.500 22.500
22.313 22.313
2844 3063
1415 1450
2848639 3067765
24.000 24.000
201.09 201.09
X52 X56
0.812 0.812
22.376 22.376
22.189 22.189
3079 3316
1683 1737
3075902 3312510
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Label 2
Grade
(in)
(in)
meter (in)
(psi)
(psi)
(lbf)
30.000 30.000
309.72 309.72
B X52
1.000 1.000
28.000 28.000
27.813 27.813
2042 3033
1364 1632
3188717 4737522
30.000 30.000
309.72 456.57
X56 B
1.000 1.500
28.000 27.000
27.813 26.813
3267 3063
1682 2999
5101946 4700608
30.000 30.000
456.57 456.57
X52 X56
1.500 1.500
27.000 27.000
26.813 26.813
4550 4900
3904 4089
6983760 7520973
36.000 36.000
373.80 373.80
B X52
1.000 1.000
34.000 34.000
33.813 33.813
1701 2528
952 1055
3848451 5717699
36.000 36.000
373.80 552.70
X56 B
1.000 1.500
34.000 33.000
33.813 32.813
2722 2552
1063 2142
6157522 5690210
36.000 36.000
552.70 552.70
X52 X56
1.500 1.500
33.000 33.000
32.813 32.813
3792 4083
2612 2692
8454026 9104336
36.000 36.000
726.24 726.24
B X52
2.000 2.000
32.000 32.000
31.813 31.813
3403 5056
3570 4766
7476991 11108672
36.000
726.24
X56
2.000
32.000
31.813
5444
5021
11963185
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Chapter 21
Derivation of the Soft String Equations 21.1
Coordinate Systems
Consider an infinitesimal element, ds, of the deformed curve of a tubular string. The local unit tangent vector, ~t, to the curve is at an inclination π − α with the global z direction (~t · ~ez = −cosα) and azimuth β with the global x direction ( ~t − ~t · ~ez ~ez · ~ex = cosβ), and is one part of a local unit vector triad, the other elements being the normal to the deformed curve, ~n = Rc d~t/ds, 1/Rc = d~t/ds , and the binormal, ~b = ~t × ~n. Recognizing that ~t = sinα (cosβ~ex + sinβ~ey ) − cosα~ez ,
(21.1)
dα dβ − sinαsinβ ~n = Rc cosαcosβ ~ex ds ds dβ dα + Rc sinαcosβ − cosαsinβ ~ey ds ds dα + Rc sinα ~ez , ds
(21.2)
then by definition,
where 1 = Rc
s
sin2 α
dβ ds
2
+
dα ds
2
.
(21.3)
Notice that ~n is undefined for d~t/ds = ~0, that is, a constant unit tangent vector. Under such conditions (dα/ds = 0 and either dβ/ds = 0 or sinα = 0), the normal vector may be arbitrarily selected from the infinity of candidates satisfying ~t · ~n = 0. A convenient choice is ~n = ~t × ~ez / ~t × ~ez which is defined for all but the trivial case of a straight, vertical wellbore. The binormal is given by
EPT Drilling
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BP Confidential
Figure 21.1. Definition of Coordinate Systems
~b = Rc sinαcosαcosβ dβ + sinβ dα ~ex ds ds dβ dα + Rc sinαsinβcosα − cosβ ~ey ds ds dβ + Rc sin2 α ~ez . ds
21.2
(21.4)
Equilibrium
The vector sum of the active forces applied to the tubular element, namely the tension, F~a = Fa~t, the resultant ~ the distributed normal force, N ~ , and the distributed friction of all distributed weight and hydrostatic loads, Q, force, F~f , must be zero, EPT Drilling
~ +N ~ + F~f = ~0, F~a + dF~a + −dF~a + Q 392
(21.5) BP Confidential
where F~a and F~f are constrained by F~a · ~t = 0,
(21.6)
~ ~ Ff = µ N ,
(21.7)
F~a · F~f = 0.
(21.8)
Further, the direction of F~f is opposite the local relative velocity between the outer surface of the tubular and the borehole wall. The terms appearing in Equation 21.5 can be further refined. First, dF~a can be decomposed by noting that ds dF~a = Fa d~t + dFa~t = Fa ~n + dFa~t, Rc
(21.9)
where the ~n component is associated with hole curvature and the ~t component is associated with a change in the magnitude of the tension. ~ consists of two contributions - the distributed weight of the tubular, γS Ap~ez , The distributed force, Q, and the resultant due to hydrostatic pressure. This latter term can be determined from Figure 21.2 and the ~ o ds, of external fluid pressure on the external divergence theorem. Consider, for example, the resultant, H lateral surface of the tube segment, ~ o ds = H
Z
po (−~en ) da = −
LateralSurf ace
Z
~ o dv − ∇p
Vo
Z
po (−~en ) da,
(21.10)
CrossSections
~ is the gradient operator, and Vo = Ao ds is the where ~en is an outwardly directed unit normal vector, ∇ ~ o = γo~ez , external volume of the tube segment. Since ∇p ~ o ds = −γo Ao ds~ez − po Ao~t + (po + dpo ) Ao − ~t + d~t H = −γo Ao ds~ez + γo Ao dz~t + po Ao d~t,
(21.11)
where higher order terms in differential quantities have been ignored. ~ i ds, of internal fluid pressure on the internal lateral surface of the tube segment Similarly, the resultant, H is ~ i ds = γi Ai ds~ez − γi Ai dz~t − pi Ai d~t. H
(21.12)
~ = γS Ap~ez + H ~o +H ~ i , and from Equations 21.1-21.4, The total distributed force can now be written as Q 21.11 and 21.12, ~ = γS Ap cosα~t − Q
pi Ai − po Ao dα dβ + we RC sinα ~n + we Rc sin2 α ~b, Rc ds ds
(21.13)
where EPT Drilling
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BP Confidential
Figure 21.2. Free Body Diagram of Element of Tube (Internal Pressure Contribution Not Shown.)
we = γS Ap + γi Ai − γo Ao .
(21.14)
The final form of the force equilibrium equation can now be written by substituting Equations 21.9 and 21.13 into 21.5,
Fe dα + we RC sinα ~n + Rc ds
! dF~e dβ ~ + F~f = ~0, − we cosα ~t + we Rc sin2 α ~b + N ds ds
(21.15)
Fe = Fa − (pi Ai − po Ao ) .
(21.16)
where
Taking successive inner products of Equation 21.15 with ~n, ~t and ~b leads to Fe dα + we RC sinα + Nn + Ff n = 0, Rc ds EPT Drilling
394
(21.17) BP Confidential
dFe − we cosα + Ff t = 0, ds we Rc sin2 α
dβ + Nb + Ff b = 0, ds
(21.18)
(21.19)
~ · ~n and similarly for the other scalar components of N ~ and F~f . where Nn = N
21.3
Normal Force Equation
The equation for rate of change of tension, or effective tension, as one moves along the tubular string is Equation 21.18. The relation for normal force, however, is more complicated, as the normal force has both normal and binormal components. The classic soft string equation for distributed normal force analyzes reciprocation only. In this case, Ff n = Ff b = 0, as all motion is tangent to the centerline of the wellbore. The magnitude of the normal force is then from Equations 21.17 and 21.19 q ~ N = Nn2 + Nb2 =
s 2 dβ Fe sinα + (Fe f racdαds + we sinα)2 . ds
(21.20)
When both rotation and reciprocation are considered, the normal force formula is more complicated, as the rotational friction affects the direction of the normal force . The correction is, however, usually small and ignored by the classic soft string model. Rotational motion, and, therefore, torque, are decoupled from the solution. Equation 21.20 is used to solve for the normal force and then, once the normal force is known, the torsion is solved as a secondary calculation.
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Part IV
Revision History
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Revision History Date 1992/1993 24th December 1993
Action Various drafts for comment. New draft for comment following 23rd September 1993 SDE Meeting at Durdent Court and detailed comments from A. Engmann, N. Bradley, T. Schofield, R. Olsen and R. Lancaster.
30th June 1994 31st October 1997 30th September 1999
Draft for Approval. First Issue (Rev 0). Whole manual reissued at Rev 1 to incorporate various changes. Whole manual reissued at Issue 2. Integrated former BPX and Amoco design manuals.
31st January 2000
Issue 2/AM01. Amendments to Crossover Design Guidance wording to increase suitability for direct use by manufacturers, to provide users options to waive detailed drawing requirements for established competent manufacturers and to specify test pressures on purchase order. There are also minor changes to machining radii requirements to ease machining. There are no integrity issues associated with continued use of the previous version of this section.
31st December 2005
Revisit entire manual, incorporating tubing stress design and additions from Arco documents, along with amendments to nearly all sections: • Adopt API TR 5C3 or ISO TR 10400 [9] symbol notation in equations (see Section 4.4.3). • Include Wellcat input guidelines (see Chapter 6). • Amend BP Standard Inventory (see Section 20.9.1) and Approved Connection list (see Chapters 17 and Section 20.9.1).
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Bibliography [1] Discussion on the jackup conductor analysis design guide. Technical Report DTD/D/42/89, DTD, September 1989. [2] Jackup conductor analysis design guide. Technical Report DTD/D/41/89, DTD, September 1989. [3] Bernt S. Aadnœy. Modern Well Design. Gulf Publishing Company, Houston, 1997. [4] A. J. Adams, S. H. L. Parfitt, T. B. Reeves, and J. L. Thorogood. Casing system risk analysis using structural reliability. SPE/IADC 25693, presented at the SPE/IADC Drilling Conference, Amsterdam, The Netherlands, February 23-25, 1993. [5] Neal J. Adams and Thommie Charrier. Drilling Engineering: A Complete Well Planning Approach. Pennwell Publishing, Tulsa, 1985. [6] American Institute of Steel Construction, Chicago. Steel Construction Manual, Thirteenth Edition, 2005. [7] American Petroleum Institute, Washington, D. C. Recommended Practice for Planning, Designing and Constructing Fixed Offshore Platforms - Working Stress Design, API Recommended Practice 2A-WSD, 2000. [8] American Petroleum Institute, Washington, D. C. Recommended Practice on Procedures for Testing Casing and Tubing Connections, API Recommended Practice 5C5, 2003. [9] American Petroleum Institute, Washington, D. C. Bulletin on Formulas and Calculations for Casing, Tubing, Drill Pipe, and Line Pipe Properties, API Bulletin 5C3, 2005. [10] American Petroleum Institute, Washington, D. C. Specification for Casing and Tubing, API Specification 5CT, 2005. [11] K. Ashida. Syntactic foams. In A.H. Landrock, editor, Handbook of Plastic Foams, Types, Properties, Manufacture and Applications, pages 147–163. Noyes Publications, New York, 1995. [12] L. Bailey. Drilling fluid and wellbore stability–current performance and future challenges. Chemicals in the Oil Industry, 1991. EPT Drilling
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[13] H. Banon, D. V. Johnson, and L. B. Hilbert. Reliability considerations in design of steel and cra production tubing strings. SPE 23483, presented at the First International Conference on Health, Safety and Environment, The Hague, Netherlands, November 10-14, 1991. [14] N. D. P. Barltrop, G. M. Mitchell, and J. B. Atkins. Fluid loading on fixed offshore structures. Technical report, HMSO, 1990. [15] BP. BPA-D-002 Well Control Manual, 2002. [16] BP. Advanced Guidelines for Deepwater Well Design, 2003. Advanced Well Design Assurance Project. [17] BP. Casing and Tubing Design Group Practice, 2008. GP 10-01. [18] D. W. Bradford, Jr. D. G. Fritchie, D. H. Gibson, S. W. Gosch, P. D. Pattillo, J. W. Sharp, and C. E. Taylor. Marlin failure analysis and redesign; part 1, description of failure. SPE Drilling and Completion, 19(2):104–111, June 2004. [19] W. B. Bradley. The effect of casing wear on the burst strength of casing, part 1, joint leakage. Journal of Engineering for Industry, 98:679–683, 1976. [20] W. B. Bradley. The effect of casing wear on the burst strength of casing, part 2, statistical burst strength of worn and unworn casing strings. Journal of Engineering for Industry, 98:686–694, 1976. [21] A. Calahorra, O. Gara, and S. Kenig. Thin film parylene coating of three-phase syntactic foams. Journal of Cellular Plastics, 23:383–398, 1987. [22] J. B. Cheatham and J. W. McEver. Behavior of casing subjected to salt loading. Journal of Petroleum Technology, 16(9):1069–1075, September 1964. [23] M. E. Chenevert. Shale alteration by water adsorption. Journal of Petroleum Technology, 22(9):1141– 1148, September 1970. [24] J. D. Clegg. Casing failure study - Cedar Creek anticline. Journal of Petroleum Technology, 23(6):676– 684, June 1971. [25] W. O. Clinedinst. Collapse safety factors for tapered casing strings. Materials, 1945. [26] P. S. B. Colback and B. L. Wiid. The influence of moisture content on the compressive strength of rocks. In Proceedings, 3rd Canadian Symposium on Rock Mechanics, pages 65–83, Toronto, 1965. [27] T. A. Cruse. Reliability-Based Mechanical Design. Marcel Dekker Inc., New York, 1997. [28] Stephen R. Daines. Prediction of fracture pressures for wildcat wells. Journal of Petroleum Technology, 34(4):863–872, April 1982. [29] R. Dawson and P. R. Paslay. Drill pipe buckling in inclined holes. Journal of Petroleum Technology, pages 1734–1738, October 1984. [30] Ben A. Eaton. Fracture gradient prediction and its application in oilfield operations. Journal of Petroleum Technology, pages 1353–1360, October 1969. EPT Drilling
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[31] Ben A. Eaton. The equation for geopressure prediction from well logs. SPE 5544, presented at the SPE 50th Annual Fall Meeting, Dallas, TX, September 28 October 1, 1975. [32] A. A. H. El-Sayed and F. Khalaf. Resistance of cemented concentric casing strings under nonuniform loading. SPE Drilling Engineering, 7(1):59–64, March 1992. [33] A. H. El-Sayed and F. Khalaf. Effect of internal pressure and cement strength on the resistance of concentric casing strings. SPE 15708, presented at the Middle East Oil Show, Bahrain, March 7-10, 1987. [34] R. C. Ellis, Jr. D. G. Fritchie, D. H. Gibson, S. W. Gosch, and P. D. Pattillo. Marlin failure analysis and redesign; part 2, redesign. SPE Drilling and Completion, 19(2):112–119, June 2004. [35] E & P Forum. Guidelines for the planning of downhole injection programmes for oil based mud wastes and associated cuttings from offshore wells. Technical Report 2.56/187, E & P Forum, March 1993. [36] L. Gibson and M. F. Ashby. Cellular Solids: Structure and Properties. Pergammon, Oxford, 1997. [37] A. S. Halal and R. F. Mitchell. Casing design for trapped annulus pressure buildup. SPE Drilling and Completion, 9(2):107–114, June 1994. [38] M. G. Hallam, N. J. Heaf, and Leslie Roger Wootton. Dynamics of Marine Structures: Methods of Calculating the Dynamic Response of Fixed Structures Subject to Wave and Current Action. CIRIA Underwater Engineering Group, 1978, London, second edition, 1978. [39] X. He and A. Kyllingstad. Helical buckling and lock-up conditions for coiled tubing in curved wells. SPE Drilling and Completion, pages 10–15, March 1995. [40] E. C. Hobaica and S. D. Cook. The characteristics of syntactic foams used for buoyancy. Journal of Cellular Plastics, pages 143–148, April 1968. [41] S. W. Gosch D. J. Horne, , P. D. Pattillo, J. W. Sharp, and P. C. Shah. Marlin failure analysis and redesign; part 3, vit completion with real-time monitoring. SPE Drilling and Completion, 19(2):120–128, June 2004. [42] N. C. Huang and P. D. Pattillo. Helical buckling of a tube in an inclined wellbore. International Journal of Non-Linear Mechanics, 35:911–923, 2000. [43] M. King Hubbert and David G. Willis. Mechanics of hydraulic fracturing. In Petroleum Transactions, pages 153–168. AIME, 1957. [44] G. T. Ju, T. L. Power, and A. G. Tallin. A reliability approach to the design of octg tubulars against collapse. SPE Paper 48332, presented at the SPE Applied Technology Workshop on Risk based Design of Well Casing and Tubing, The Woodlands, Texas, May 7-8, 1998. [45] F. Khalaf. Increasing casing collapse resistance against salt-induced loads. SPE 13712, presented at the Middle East Oil Technical Conference and Exhibition, Bahrain, March 11-14, 1985. EPT Drilling
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[46] F. J. Klever and G. G. Stewart. Analytical burst strength prediction of octg with and without defects. SPE 48329, presented at the SPE Applied Technology Workshop on Risk based Design of Well Casing and Tubing, The Woodlands, Texas, May 7-8, 1998. [47] E. M. Kocian, R. N. Mefford, L. B. Hilbert, and I. A. Kalil. Compressive loading casing design. SPE/IADC 19923, presented at the SPE/IADC Drilling Conference, Houston, February 27-March 2, 1990. [48] Y. Kuriyama, Y. Tsukano, and T. Mimake. Effect of wear and bending on casing collapse strength. SPE 24597, presented at the SPE Annual Technical Conference and Exhibition, Washington, DC, October 4-7 year =. [49] I. M. Kutason and A. K. Takghi. Better deep hole BHCT estimation possible. Oil and Gas Journal, May 25 1987. [50] N. Last, S. Mujica, P. D. Pattillo, and G. Kelso. Evaluation, impact, and management of casing deformation caused by tectonic forces in the andean foothills, colombia. SPE Drilling and Completion, 21(2):116–124, June 2006. [51] D. B. Lewis, P. R. Brand, and M. A. Maes. The use of qra technology in drilling and well operations. SPE 48323, presented at the SPE Applied Technology Workshop on Risk Based Design of Well Casing and Tubing, The Woodlands, Texas, May 7-8, 1998. [52] A. Lubinski, W. S. Althouse, and J. L. Logan. Helical buckling of tubing sealed in packers. Journal of Petroleum Technology, pages 655–670, June 1962. [53] L. A. MacPherson and L. N. Berry. Prediction of fracture gradients from log derived elastic moduli. Log Analyst, 13:12–19, September 1972. [54] M. A. Maes, K. C. Gulati, D. L. McKenna, P. R. Brand, D. B. Lewis, and D. B. Johnson. [55] J. W. Martin. Selection and Treatment of Acids, Scale Dissolvers and Clear Brines to Avoid Corrosion Failure (2007 Edition), BP ETP GN 06-004. EPTG, 2007. [56] J. W. Martin, W. Durnie, and A. Leonard. Guidelines for Selecting Downhole Tubing and Casing Materials for Oil & Gas Production Wells (2006 Edition), BP ETP Guidance Note GN 036-13. EPTG, 2006. [57] C. Marx and A. A. H. El-Sayed. Evaluation of collapse strength of cemented pipe-in-pipe casing strings. SPE/IADC 13432, presented at the SPE/IADC Drilling Conference, New Orleans, March 6-8, 1985. [58] W. R. Matthews and J. Kelly. How to predict formation pressure and fracture gradient. Oil and Gas Journal, 65:92–106, February 1967. [59] F. K. Modi and A. H. Hale. A borehole stability model to couple the mechanics and chemistry of drilling fluid/shale interaction. SPE 25628, presented at the SPE/IADC Drilling Conference, Amsterdam, The Netherlands, February 23-25, 1993. EPT Drilling
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[60] S. C. Morey. GIS 02-102 (Revision 1) Guidance Document for the Hard Facing of Drill String Components. EPTG, 2004. [61] S. C. Morey. GIS 02-204 (Revision 3) Specification for Sour Service Grades C110 and C125 Low Alloy Steel OCTG Seamless Pipe. EPTG, 2006. [62] S. C. Morey. GIS 02-201 (Revision 3) Specification for OCTG Seamless Casing and Tubing [ISO 11960 & API Spec 5CT]. EPTG, 2007. [63] S. C. Morey. GIS 02-202 (Revision 1) Specification for OCTG EW Casing [ISO 11960 & API Spec 5CT]. EPTG, 2007. [64] S. C. Morey. GIS 02-203 (Revision 6) Specification for OCTG Crossover Connectors. EPTG, 2007. [65] S. C. Morey. GIS 02-206 (Revision 9) Specification for Duplex and Super Duplex 25% Chrome Stainless Steel Seamless Pipe. EPT, 2008. [66] NACE International. NACE MR-0175, Petroleum and Natural Gas Industries–Materials for Use in H2S-Containing Environments in Oil and Gas Production, 2003. [67] NACE International. NACE SP-0186, Application of Cathodic Protection for External Surfaces of Steel Well Casings, 2003. [68] J. H. Nester, D. R. Jenkins, and R. Simon. Resistances to failure of oil-well casing subjected to nonuniform transverse loading. American Petroleum Institute Drilling and Production Practice 1955, pages 374–378, 1956. [69] K. Okuno and R. T. Woodhams. Mechanical properties and characterization of phenolic resin syntactic foams. Journal of Cellular Plastics, pages 237–244, September 1974. [70] J. W. Oldfield, G. L. Swales, and B. Todd. Corrosion of metals in deaerated seawater. In Proceedings, 2nd BSE-NACE Corrosion Conference, pages 65–83, Bahrain, 1981. [71] S. H. L. Parfitt and J. L. Thorogood. Application of qra methods to casing seat selection. SPE 28909, presented at the European Petroleum Conference, London, October 25-27, 1994. [72] P. Paslay, E. P. Cernocky, and R. Wink. Burst prediction of thin walled, ductile tubulars subjected to axial load. SPE 48327, presented at the SPE Applied Technology Workshop on Risk Based Design of Well Casing and Tubing, The Woodlands, Texas, May 7-8, 1998. [73] P. D. Pattillo, B. W. Cocales, and S. C. Morey. Analysis of an annular pressure buildup failure during drill ahead. SPE Drilling and Completion, 21(4):242–247, December 2006. [74] P. D. Pattillo and T. G. Kristiansen. Analysis of horizontal casing integrity in the valhall field. SPE 78204, presented at the SPE/ISRM Rock Mechanics Conference, Irving, Texas, October 20-23, 2002. [75] P. D. Pattillo, N. Last, and W. T. Asbill. Effect of nonuniform loading on conventional casing collapse resistance. SPE Drilling and Completion, 19(3):156–163, September 2004. EPT Drilling
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[76] P. D. Pattillo, Z. A. Moschovidis, and M. Lal. An evaluation of concentric casing for nonuniform load applications. SPE Drilling and Completion, pages 186–192, September 1995. [77] P. D. Pattillo, R. D. Pruitt, A. I. Al Nakbi, J. L. Gent, K. Young, and X. Zhang. Repair intervention of worn production casing in the sajaa field. SPE 81537, presented at the SPE 13th Middle East Oil Show and Conference, Bahrain, April 5-8, 2003. [78] P. D. Pattillo and T. E. Rankin. How Amoco solved casing design problems in the Gulf of Suez. Petroleum Engineer, pages 86–112, November 1981. [79] P. D. Pattillo, U. B. Sathuvalli, S. M. Rahman, H. H. Prewett, S. P. Carmichael, and R. Wydrinski. Mad dog slot w1 tubing deformation failure analysis. SPE 109882, presented at the SPE Annual Technical Conference and Exhibition, Anaheim, California, November 11-14, 2007. [80] J. Pattinson. Erosion guidelines on allowable velocities for avoiding erosion and on the assessment of erosion risk in oil and gas production systems. Technical Report ESR.94.ER.070, BP Sunbury, July 1994. [81] M. L. Payne and J. D. Swanson. Application of probabilistic reliability methods to tubular design. SPE Drilling Engineering, 5(4):299–305, December 1990. [82] E. S. Pennebaker. An engineering interpretation of seismic data. SPE 2165, presented at the SPE 43rd Annual Fall Meeting, Houston, Texas, September 29-October 2, 1968. [83] M. Rylance. Cuttings reinjection feasibility study for the andrew field development wells. Technical Report 041, BP Sunbury, August 1993. [84] M. Rylance. Cuttings reinjection feasibility study for the miller field. Technical Report 042, BP Sunbury, September 1993. [85] F. A. Shutov. Syntactic polymer foams. [86] G. Sirevag and A. Bale. An improved method for grinding and reinjecting of drill cuttings. SPE 25758, presented at the SPE/IADC Drilling Conference, Amsterdam, The Netherlands, February 22-25, 19937. [87] M. B. Smith and P. D. Pattillo. Analysis of casing deformations due to formation flow. In Proceedings, Applied Oilsands Geoscience Conference, Edmonton, Alberta, 1980. [88] G. Soave. Equilibrium constants from a modified redlich-kwong equation of state. Chemical Engineering Science, 27:1197, 1972. [89] B. Stahl and M. P. Baur. Design methodology for offshore platform conductors. Journal of Petroleum Technology, pages 1973–1984, November 1983. [90] G. Stewart and F. J. Klever. Accounting for flaws in the burst strength of octg. SPE 48330, presented at the SPE Applied Technology Workshop on Risk Based Design of Well Casing and Tubing, The Woodlands, Texas, May 7-8, 1998. EPT Drilling
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[91] S. P. Timoshenko and J. M. Gere. Theory of Elastic Stability. McGraw-Hill Book Company, New York, 1961. [92] A. P. A. Vorenkamp. A theory of resultant burst loads for designing production casing: Principally in abnormally pressured wells. SPE 17178, presented at the SSPE/IADC Drilling Conference, Dallas, Texas, February 28-March 2, 1988. [93] J. V. Walters. Internal blowouts, cratering, casing setting depths, and the location of subsurface safety valves. SPE Drilling Engineering, 6(4):285–292, December 1991. [94] H. G. Weurfer. Annotated tables of strength and elastic properties of rocks. SPE Drilling Reprint Series. [95] R. J. K. Wood. Technical report. [96] M. Zamora. New method predicts gradient fracture. Petroleum Engineer International, pages 38–47, September 1989.
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Index 10XX series
anode, 344, 347, 348
defined, 30
APB, see annular pressure build-up API documents, see ISO documents
41XX series
API material grade
defined, 30
defined, 31
43XX series
API Modified thread compound, 313
defined, 30
API tubulars AFE, see annular fluid expansion
chemistry, 354
AISI steel grade
couplings, 360
defined, 30
coating, 361
ammonium
marking, 360
as oxygen scavenger, 342
thread protection, 361
annealing
groups, 352
defined, 30
inspection, 354
annular fluid expansion, see annular pressure buildup
dimensions and tolerances, 354 drift diameter, 356
abbreviated, 30
electromagnetic inspection, 359
annular pressure
flaw inspection, 359
equivalent circulating density, 103
hydrostatic test, 356
loss calculation for laminar flow, 104
magnetic particle inspection, 359
static fluid density, 103
mechanical properties, 357
annular pressure build-up, 56, 71, 231, 233, 234, 236– 238, 240–248, 255, 259
range length, 355 ultrasonic, 359
abbreviated, 31
manufacturing process, 352
calculation principles, 231
ASV, see annulus safety valve
example, 235
austenite
mitigation, 236 nitrified foam spacer, 236
defined, 31 austenitic stainless steel
rupture disks, 246 syntactic foam, 256
defined, 31 axial force
annulus safety valve
components, 156
abbreviated, 31
air weight, 157
annulus safety valves, 131
ballooning, 161
annulus test, 133
bending, 160
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bump plug, 160
C90, 336
buoyancy, 158
C95, 336
fluid friction, 163
carbon dioxide, 9, 337, 345 effect on casing setting depth, 13, 95
landing force, 161 overpull force, 161
carbon steel defined, 31
shock load, 164 temperature, 162 drilling and production, 166
carbonic acid, 345 casing seat selection objective, 91
installation loads, 164 as-cemented, 166
casing setting depth
cementing casing, 165
bottom-up method, 94
running casing, 165
conductor driving, 104 conductor guidelines, 101
tubing design, 166 expansion devices, 167
annular pressure loss, 104
load cases, 167, 168
effective mud weight, 102 equivalent circulating density, 103
backreaming
example problem, 96
effect on wear, 192, 196
general guidelines, 92
biocides, 338
Gulf of Mexico guidelines, 111
bisulphites
deep water, 113
as a source of hydrogen sulfide, 346
shallow water, 111
BP Well Control Manual, 95, 143, 349
initial estimates, 94
Brinell hardness test
Keathley Canyon example, 115
defined, 33
North Sea guidelines, 109
buoyed weight
conductor casing, 109
calculation for installation loads, 11
surface casing, 110
burst
North Sea HPHT guidelines, 110
casing post-installation loads
structural conductor guidelines, 101
external pressure, 148 internal pressure, 148
top-down method, 94 casing types
design factor, 145 design issues, 143
production casing, 92 casing wear
effect of axial load, 143
abrasive wear, 187
installation loads, 146
adhesive wear, see galling
cementing, 146
caliper recommendation, 209
running, 146
casing rating calculations, 196
tubing, 148
collapse, 197
tubing post-installation loads
internal yield pressure, 196
external pressure, 153
centralizers, 208
internal pressure, 153
design imperatives, 208
Buta-N, 255 EPT Drilling
doglegs, 193 410
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drill pipe protectors, 208
stab-in job, 126
estimation, 193
Charpy test
example, 196
defined, 31
input, 194
chlorine, 9
interpretation of results, 195
CO2 , see carbon dioxide
procedure, 194
coefficient of variance
hard-banding, 187, 189, 190, 195, 196, 201, 203, 204, 206, 208
defined, 31 cold working
measuring/monitoring, 207 acoustic calipers, 207
defined, 31 collapse
caliper summary, 208
design factor, 124
electromagnetic calipers, 207
design issues, 123
mechanical calipers, 207
effect of axial load, 123
minimizing wear, 197
evacuation, 128
casing material, 201
high collapse casing, 141
cementing, 201
installation loads, 124
centralizers, 201
cementing, 125
crossovers, 201
tubing, 127
drill pipe protectors, 204
post-installation loads, 127
hard-banding, 203
conductor casing, 127
mud types, 206
intermediate casing, 130
tapered casing strings, 202
production casing, 130
parameters, 187
production tubing, 132
prediction, 189
rating, 133
contact pressure, 190
example calculation, 137
tripping tools, 189
non-uniform loading, 137
sidetrack, 208
uniform loading, 134
tripping, 208 wear coefficient, 195
waiting on cement, 126 column buckling
wear groove, 187
casing wear, 177
wear rate, 208
critical buckling value, 178
well design guidelines, 192
curved wellbore, 181
well trajectory, 208
design considerations, 177
CasingSeat
effect of hole curvature, 181
described, 54
effective tension, 178
software tool, 53
example calculation, 179
use, 58
external pressure, 178, 179, 184
cathode, 345, 347
internal pressure, 178, 179, 184
cementing
relation to true tension, 179
conventional, 125
effective weight, 180
external corrosion control, 343 EPT Drilling
relation to air weight, 180 411
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example calculation, 184
families, 321
helical, 180
flush, 323
bending stresses, 16, 183
galling, 315, 317, 321, 323
mitigation, 184
Grant Prideco 2 Step, 4 or 6 Pitch, 327, 362–364
pitch, 16, 182
Grant Prideco 2 Step, 8 Pitch, 327, 362–367
radius of curvature, 16, 183
Grant Prideco Advanced NJO, 326, 364–374
inclined wellbore, 180
Grant Prideco ATS-E, 325, 367–376
issues, 177
Grant Prideco STL, 326, 362–368
mitigation
Grant Prideco TC-II, 325, 365–373
overpull, 184, 185
Grant Prideco VIPER, 324, 376–381
packer configuration, 184
Grant Prideco XLCS, 324, 376–381
top of cement, 184
Grant Prideco XLCS-RB, 324, 376–381
neutral point, 179
Grant Prideco XLF, 324, 376–381
sinusoidal, 180
Grant Prideco XLF-RB, 324, 376–381
snakey, 180
Grant Prideco XLW, 324, 376–381
tool passage, 177, 183, 184
Hunting BOSS, 325, 368–376
vertical wellbore, 180
Hunting SEAL LOCK HC, 325, 364–374
yield, 181
Hunting SEAL LOCK HT, 325, 362–367
completion fluid
Hunting SLF, 326, 362–368 Hunting SLSF, 326, 364–374
defined, 341 conductor casing
Hunting TKC, 311
defined, 31
integral, 322 internal profile, 318
connections API BUTTRESS, 325, 364–373
internal stresses, 317 cylindrical threads, 317
API Buttress, 310, 312, 314, 317, 321, 322, 327 API EUE, 309, 321
torque shoulder, 317
API EUE 8R, 325, 362–364
JFE Bear, 325, 362–370
API LT&C, 309, 317, 321, 325, 364–370
joint strength load flank, 310
API NUE, 309, 321
upsets, 310
API Round Thread, 310 API ST&C, 309, 321
junpout, 309–311, 321
approved connection list, 323
leak resistance, 313
Benoit BTS-6, 318
BP Classes, 315
Benoit/Hunting 2 Step, 4 or 6 Pitch, 327, 362– 364
metal-to-metal seal, 315 R Teflon ring, 314
Benoit/Hunting 2 Step, 8 Pitch, 327, 362–367
metal-to-metal seal, 322, 323
critical section area, 310
multidimensional loading, 318
Dril-Quip MULTI-THREAD, 324, 376–381
Oil States LEOPARD SD, 324, 376–381
Dril-Quip QUIK-JAY, 324, 376–381
Oil States LYNX, 324, 376–381
Dril-Quip QUIK-STAB, 324, 376–381
Oil States MERLIN, 324, 376–381
Dril-Quip QUIK-THREAD, 324, 376–381
Oil States SWIFT DW2, 324, 376–381
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semi-flush, 323
pitting, 345, 347
Tenaris-Hydril 2 Step, 4 or 6 Pitch, 327, 362–364 Tenaris-Hydril 2 Step, 8 Pitch, 327, 362–367
critical pitting temperature, 348 corrosion control
Tenaris-Hydril 501, 327, 362–364
external, 343
Tenaris-Hydril 503, 327, 362–364
internal, 337
Tenaris-Hydril 511, 326, 362–372, 374, 375
aqueous phase, 344
Tenaris-Hydril 513, 326, 364–374
completion fluids, 341
Tenaris-Hydril 521, 314, 326, 363–375
corrosion background, 344
Tenaris-Hydril 523, 326, 367–374
drilling operations, 337
Tenaris-Hydril 531, 327, 362–364
production operations, 340
Tenaris-Hydril 533, 327, 362–368
sulfide stress cracking, 338
Tenaris-Hydril 551, 327, 362–364
corrosion guidelines, see material selection
Tenaris-Hydril 553, 327, 362–368
corrosion rate
Tenaris-Hydril 561, 325, 362–364 Tenaris-Hydril 563, 325, 362–374
effect of pH, 338 corrosion resistant alloy, 280, 317, 334, 342
Tenaris-Hydril Blue, 325, 362–374
abbreviated, 31
Tenaris-Hydril GP-3P, 325, 374–376
CRA, see corrosion resistant alloy
Tenaris-Hydril MAC II, 326, 366–374
cross-sectional stability, see collapse
Tenaris-Hydril SLX, 312, 326, 364–374
CSON 59
tensile efficiency, 309
relevence to non-sour casing, 339
defined, 309 threaded and coupled, 322
replacement by PON 13, 340 cuttings re-injection, 281
upset, 322
annular clearance, 291
V&M/SMI DINO VAM, 325, 370–375
burst and collapse, 292
V&M/SMI FJL, 326, 362–368
cementing, 287
V&M/SMI SLIJ-II, 319, 320, 326, 365–374
centralization, 288
V&M/SMI VAM HW ST, 325, 365–374
contingencies, 291
V&M/SMI VAM TOP, 325, 362–374
density and volume, 290
V&M/SMI VAM TOP HC, 325, 365–369
pipe movement, 289
V&M/SMI VAM TOP HT, 325, 365–367
sampling and testing, 290
V&M/SMI VAM TOP KP, 325, 365–368
shoe location, 288
VAM SLIJ II, 316
spacers, 289
VAM TOP, 313, 316, 319
special cases, 291
Vetco Gray RL-1, 324, 376–381
tops of cement, 289
Vetco Gray RL-4, 324, 376–381
corrosion, 286
Vetco-Gray ALT-2, 324, 376–381
use of de-aerated seawater, 286
Vetco-Gray ST-2, 324, 380
use of raw seawater, 287
weld on, 323
description, 282
contact force, see normal force
design features, 282
corrosion background
erosion, 282
crevice corrosion, 347 EPT Drilling
annular casing, 285 413
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re-injection point, 283
duplex stainless steel
wellhead, 282
defined, 32
seal integrity, 295 EA, see Engineering Authority
CWear, 57, 58, 85–89, 190, 193, 195, 202 described, 57
ECD, see equivalent circulating density
dogleg insertion, 86
effective tension defined, 394
drill pipe protectors, 86
effective weight
performance property calculations, 87
defined, 394
software tool, 54 tortuosity, 86
elastomer, 348
use, 85
electric resistance weld abbreviated, 32
with casing design software, 87
defined, 32 deepest subsequent open hole, 128, 130
electric submersible pump, 12, 130, 132
abbreviated, 32
electrolyte, 345
density
elongation
cuttings, 103
defined, 32
depth uncertainty
Engineering Authority, 5, 6
effect on casing setting depth, 13, 95
Engineering Technical Practice, 5, 6
design formula
deviations, 5
defined, 31
archiving, 6
deterministic
permanent to an SPU, 5
defined, 32
solitary, 6
development well, 10, 30, 51, 129, 130, 148–152, 337
environment-sensitive cracking, 345
deviation from policy, 23, 150
EPT, see Exploration and Production Technology
diesel
equivalent circulating density, 93, 101, 103, 104, 206
as a completion fluid, 343
abbreviated, 32
differential sticking effect on casing setting depth, 13, 95
defined, 32 equivalent stress, 124
DLS, see dogleg severity
ERW, see electric resistance weld
dogleg severity
ESC, see environment sensitive cracking
abbreviated, 32
ESP, see electric submersible pump
defined, 32
ETP, see Engineering Technical Practice
drill stem test, 12, 26, 82, 110, 150, 152, 218, 221 abbreviated, 32
evacuation, 128, 130, 132 Exploration and Production Technology, 3, 22, 29,
production load cases, 12
56, 59, 129, 133, 141, 196, 221, 227, 231, 250, 256, 266, 323–327, 332, 351
drilling casing, see intermediate casing Drilling Training Alliance, 58
exploration well, 30, 55, 130, 148–150, 337
drive pipe, 111 DSOH, 130, see deepest subsequent open hole
vs. development well, 9, 49 external pressure, 16, 22, 24–26, 38, 123, 124, 127,
DST, see drill stem test EPT Drilling
130–134, 137, 143, 145, 146, 148, 149, 153, 414
BP Confidential
156, 161, 167, 171, 172, 175, 177–179, 197,
L80, 332
232, 250, 254, 276, 318, 320
N80, 332, 338 P110, 339
fatigue defined, 32 ferrite defined, 32 ferritic stainless steel defined, 33 First Order Reliability Method, 306 abbreviated, 33 flowchart
SM125S, 332, 341 T95, 332 GRP, see glass reinforced plastic H2 S, see hydrogen sulfide H40, 336 hammers diesel described, 104
connection selection, 325 material selection casing, 332 FORM, see First Order Reliability Method formation strength effect on casing setting depth, 13, 95 fracture gradient effect on casing setting depth, 93 estimation, 106 fresh water sands effect on casing setting depth, 13, 95 Functional Well Specification abbreviated, 33 defined, 49 example, 50 impact on tubular design, 49 sidetracking requirements, 13, 95 FWS, see Functional Well Specification galling, 187 gas kick profile, 110, 144, 150, 349
specifications, 104 hydraulic, 105 hardenability defined, 33 hardness defined, 33 HB, see Brinell hardness test Health and Safety Executive, 110 HIC, see hydrogen induced cracking high pressure effect on casing setting depth, 13, 95 high viscosity sweep, 103 hole cleaning effect on casing setting depth, 13, 95 HRC, see Rockwell hardness test HSE, see Health and Safety Executive HV, see Vickers hardness test hydrogen induced cracking, 334 abbreviated, 33 hydrogen sulfide, 9, 337, 340, 341
gas lift, 130–132 general corrosion, 345
effect on casing setting depth, 13, 95
geotechnical data sources, 105
scavengers, 339
glass reinforced plastic, 201 GOM, see Gulf of Mexico grades C110, 332, 340
preventive measures in drilling mud, 339 sources in drilling mud, 338 intermediate casing defined, 33 internal pressure, 11, 16, 22, 24–26, 123, 124, 130–
C90, 332 EPT Drilling
133, 137, 143–146, 148–153, 161, 167, 171– 415
BP Confidential
173, 175, 178, 179, 232, 250, 253, 276, 299, 315, 320, 323, 328
abbreviated, 33 lost circulation zone
iron carbide defined, 33
effect on casing setting depth, 13, 94 LOT, 111, see leak-off test
iron carbonate, 345 iron sulfide, 342, 346
MAASP, 133
ISO 11960, 39, 145, 332, 336, 351–353, 355–357, 359–
machined crossover design guidance, 296 excessive stress, 296
361 ISO 15156, 332, 334–336
abrasion, 297
ISO documents
corrosion, 297 design control, 297
TR 10400, 22, 133, 137, 141, 300, 303, 351, 356, 399
fatigue, 297 incorrect connection, 296
J55, 336
non-uniform material properties, 296
jackup
repeated use, 297
conductor driving, 104, 105 structural conductor
stress concentrations, 296 martensite
design guidelines, 225 loads, 225 jet pump, 132 K55, 336
defined, 34 martensitic stainless steel defined, 34 material selection process, 331
kick tolerance, 54, 95, 110, 115, 116, 349 acceptable values, 95
mud and brine exposure, 332
defined, 349
NACE “standard approach”, 335
effect on casing setting depth, 95
qualifying materials for specific conditions, 336 sour service, 332 scope, 331
L80, 332, 336 Label 1
mean, 92, 303
defined, 33
defined, 34
Label 2 defined, 33
MIC, see microbiologically induced corrosion
Lame´equations, 174, 243
microbiologically induced corrosion, 287
LC, see lost circulation
minimum internal yield pressure, 247, 248, 251, 253,
microannulus, 161
leak-off test, 149 abbreviated, 34 limit state formula
254 MIYP, see minimum internal yield pressure monel
defined, 33
defined, 34
limited kick, see gas kick profile
Monte Carlo, 306
localized corrosion, 345
multiple string analysis, 166
Lock Tite 272, 255 lost circulation, 127–129 EPT Drilling
N80, 336 416
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NACE, see National Association of Corrosion Engi- production casing neers Nitrile, 255 normal force, 157 normalizing
defined, 34 production tubing defined, 34 proof stress
defined, 34
defined, 35
OCTG, see oil country tubular goods
Q125, 336
oil country tubular goods abbreviated, 34
quenching
oxygen, 338, 342, 346, 348 oxygen scavenger, 347
quick design
P110, 336
quick guide
defined, 35 minimum design factors, 22 buckling and compression, 16
packer, 130 hydraulic set, 160, 165, 169
critical force for sinusoidal buckling, 16
PBR, see polished bore receptacle PDDP, see Pre-Drill Data Package
effective force, 16
PDF, see probability distribution function pearlite
post-buckled geometry, 16
mitigating buckling, 17 burst design, 14 casing setting depths, 13
defined, 34 Poisson’s ratio, 161
casing wear, 17 design rules, 17
policy software
collapse design, 13 connection selection, 22
safety critical software, 53 polished bore receptacle, 157, 167, 169
design data, 9 design summary, 10
abbreviated, 34
drilling load cases for casing, 12
seals, 169 polished bore recepticle, 133
installation loads, 10 casing, 10, 11
pore pressure, 130 effect on casing setting depth, 92
tubing, 11
Pre-Drill Data Package abbreviated, 34
introduction, 9
contents, 51 precipitation hardening stainless steel
production load cases for casing, 12
defined, 34 probabilistic method
reliability, 22
defined, 34 probability distribution function, 301
temperature, 18
material selection, 22 production load cases for tubing, 12 special design cases, 21 bullhead kill, 21 drilling, 19
abbreviated, 34 producing intervals
production, 20
effect on casing setting depth, 13, 95 EPT Drilling
water injection, 21 417
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tension design, 14
effect on casing setting depth, 13, 95
cementing, 14 drilling and production, 15
sandstone
initial condition, 14 running, 14
SCC, see stress corrosion cracking
chemical activity, 92 seamless tubular
triaxial design, 15 reduction of area defined, 35 reliability history in tubular design, 299 hybrid design explained, 302
defined, 35 Segment Engineering Technical Authority, 5, 6 SET, see solid expandable tubular SETA, see Segment Engineering Technical Authority shale chemical activity, 92 shallow gas effect on casing setting depth, 13, 94
performance properties probabilistic description, 303
shallow water flow
population defined, 303
sidetracking requirements
probabilistic design compared to working stress design, 302
Site Technical Practice, 5, 6
explained, 300 sample defined, 303 sample size defined, 303 working stress design compared to probabilistic design, 302 explained, 299
effect on casing setting depth, 94 effect on casing setting depth, 13, 95 sizing tubulars, 117 intermediate and surface casing, 118 production casing, 117 production tubing, 117 sodium bisulphite as oxygen scavenger, 342 soft string model derivation of governing equations, 391 coordinate systems, 391
revision history, 400
equilibrium equations, 392
rock
normal force equation, 395
chemical activity, 92
torsion, 395
differential sticking, 91, 92 permeability, 91
solid expandable tubular, 124
weakness, 92 caving, 92
sour service, 332
SOR, see Statement of Requirements domain charts, 337
fracture, 92 sloughing, 92 spalling, 92 Rockwell hardness test, 33 defined, 33 rod pump, 132
partial pressure, 337 pH, 337 sour resistant grades, 336 SRB, see sulphate reducing bacteria SSC, 354, see sulfide stress cracking stainless steel
salt EPT Drilling
austenitic, 347 418
BP Confidential
defined, 35
wellhead movement, 56
Standard BP Inventory
Window menu, 68
defined, 351
structural conductor casing
tabulated, 361
defined, 35
standard deviation
submerged-arc weld
defined, 35
defined, 35
standard deviation, 303
subsea tieback design, 264
Statement of Requirements, see Functional Well Spec-
design problems, 266
ification
engineering interface, 269
statistics
initial design, 274
standard deviation, 419
example calculation, 278
STP, see Site Technical Practice
heat shrink sleeve installation, 277
stress corrosion cracking, 332, 335, 347
thermal growth, 274
abbreviated, 35
installation sequence, 272
effect of manufacturing technique, 337
loading, 270
stress relief
environmental, 270
defined, 35
service life, 271
StressCheck, 53–59, 69–71, 88, 89, 148, 211, 221, 296
operational aspects, 269
allowable wear, 195
overview, 266
annular pressure build-up, 56
subsea well, 161
BP template, 59, 221
sulfide stress cracking, 334
complex design, 55
abbreviated, 35
connections, 57 described, 54
described, 346 sulphate reducing bacteria
design assumptions, 69
abbreviated, 35
Edit menu, 62
as a source of hydrogen sulfide, 346
File menu, 59, 60
Sumitomo, 332
friction effects, 56
surface casing
Help menu, 69 input guidelines, 59
defined, 36 surge
load capacity diagram, 172 software tool, 53
effect on casing setting depth, 93 surge pressure
sour service, 57 temperature calculation, 54
effect on casing setting depth, 13, 95 swab
temperature modeling, 218 Tools menu, 68
effect on casing setting depth, 93 synthesis method
triaxial check, 171
defined, 36
Tubular menu, 64 use, 58, 182
T95, 336
View menu, 67
TA, see Technical Authority
Wellbore menu, 63
tapered string, 159, 169
EPT Drilling
419
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Technical Authority, 5, 6 temperature
formula, 171 trip margin
Centigrade to Fahrenheit conversion, 212 Fahrenheit to Centigrade conversion, 211
effect on casing setting depth, 93 true vertical depth
geothermal gradient, 212
abbreviated, 36
temperature profile
calculating gravity loads, 14
abbreviations, 211
tubingless completion, 177
bullheading, 218
TVD, see true vertical depth
cementing, 214 example calculation, 215 drilling, 216
United Kingdom Offshore Operators Association, 110 units, 45 angle, 45
example calculation, 218
axial length, 45
production, 217
coefficient of thermal expansion, 45
example calculation, 218
compressibility, 45
static, 212 defined, 212
concentration, 45
example calculation, 214
cross-sectional area, 45
offshore, 212
curvature, 45
onshore, 212
density (fluid), 47 diameter, 46
water or gas injection, 219
force, 46
tempering
force per length, 46
defined, 36
frequency, 46
tensile strength
height, 46
defined, 36
Hybrid, 45
toughness
inertia, 46
defined, 36
limit stress, 46
triaxial design design statement, 171
mass flow rate, 46
example calculation, 175
mass per length, 46
load capacity diagram, 172
pressure, 46
purpose, 171
radial length, 46
relation to API collapse equation, 173
radius of curvature, 46
relation to Barlow’s equation, 171, 173
rate of penetration, 46
safety factor calculation, 175
SI, 45
stress calculation, 173
stiffness, 46
axial stress, 173
strain, 46
circumferential stress, 174
stress, 46
radial stress, 174
temperature, 46 temperature gradient, 46
triaxial stress design factor
time, 46
defined, 172 von Mises equivalent stress, 171 EPT Drilling
true vertical depth, 46 420
BP Confidential
US Customary, 45
complex design, 55
velocity, 47 viscosity, 47
described, 57 friction effects, 56
volume, 47 volumetric flow rate, 47
Inventories menu, 72 load capacity diagram, 172
wear factor, 47 US Customary
Loads menu, 83 software tool, 53
abbreviated, 36 UTS, see tensile strength
structure, 70 temperature calculation, 54 temperature modeling, 215, 217–219 triaxial check, 171
Vickers hardness test, 33 defined, 33
tubing design, 57 use, 70, 166, 182
Viton, 255 VIV, see vortex induced vibration von Mises equivalent stress
Wellbore menu, 80 wellhead movement, 56
defined, 171 vortex induced vibration, 225, 227
wellhead loads, 279 WellPlan, 17, 56, 171, 194 Torque Drag module, 17, 56, 194
abbreviated, 36
Wellplan Torque Drag module, 205
waiting on cement, 126, 156, 160, 161, 166 abbreviated, 36 applied surface pressure, 11
WOC, see waiting on cement working stress design, 299
drilling load cases, 12 installation loads, 11
abbreviated, 36 WPDP, see Well Planning Data Package
well control effect on casing setting depth, 94
WSD, see working stress design
well depth effect on casing setting depth, 13, 95 Well Planning Data Package, see Pre-Drill Data Package abbreviated, 36
yield strength defined, 36 Young’s modulus defined, 36
well trajectory effect on casing setting depth, 13, 95
zinc bromide, 343
wellbore inclination effect on casing setting depth, 93 wellbore stability chemical mechanisms, 92 effect on casing setting depth, 13, 93, 94 Wellcat, 18, 53, 55–58, 61, 70–73, 77, 80, 82–84, 167, 211, 215, 220, 232, 233, 236, 241, 244, 246, 272, 399 annular pressure build-up, 56 EPT Drilling
421
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