ISO/TR 13624-2:2009
(Main)Petroleum and natural gas industries — Drilling and production equipment — Part 2: Deepwater drilling riser methodologies, operations, and integrity technical report
Petroleum and natural gas industries — Drilling and production equipment — Part 2: Deepwater drilling riser methodologies, operations, and integrity technical report
ISO/TR 13624-2:2009 pertains to mobile offshore drilling units that employ a subsea BOP stack deployed at the seafloor. It is intended that the drilling riser analysis methodologies discussed in this part of ISO 13624 be used and interpreted in the context of ISO 13624-1.
Industries du pétrole et du gaz naturel — Équipement de forage et de production — Partie 2: Méthodologies, opérations et rapport technique d'intégrité relatifs aux tubes prolongateurs pour forages en eaux profondes
General Information
Standards Content (Sample)
TECHNICAL ISO/TR
REPORT 13624-2
First edition
2009-12-01
Petroleum and natural gas industries —
Drilling and production equipment —
Part 2:
Deepwater drilling riser methodologies,
operations, and integrity technical report
Industries du pétrole et du gaz naturel — Équipement de forage et de
production —
Partie 2: Méthodologies, opérations et rapport technique d'intégrité
relatifs aux tubes prolongateurs pour forages en eaux profondes
Reference number
ISO/TR 13624-2:2009(E)
©
ISO 2009
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ISO/TR 13624-2:2009(E)
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ii © ISO 2009 – All rights reserved
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ISO/TR 13624-2:2009(E)
Contents Page
Foreword .iv
Introduction.v
1 Scope.1
2 Normative references.1
3 Terms and definitions .1
4 Abbreviated terms .7
5 Coupled drilling riser/conductor analysis methodology and worked example.7
5.1 Coupled methodology.7
5.2 Decoupled methodology.7
5.3 Analysis considerations .10
5.4 Model development.10
5.5 Coupled riser analysis .19
5.6 Decoupled riser analysis .21
5.7 Worked example .22
5.8 Basis of analysis .22
5.9 Model description and analysis procedure .29
5.10 Results.30
6 Drift-off/drive-off analysis methodology and worked example .33
6.1 Drift-off analysis methodology .33
6.2 Example.36
7 Recoil analysis methodology and worked example .50
7.1 Introduction.50
7.2 Background.50
7.3 Required information .57
7.4 Performance criteria.64
7.5 Worked example applicability .68
Bibliography.88
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ISO/TR 13624-2:2009(E)
Foreword
ISO (the International Organization for Standardization) is a worldwide federation of national standards bodies
(ISO member bodies). The work of preparing International Standards is normally carried out through ISO
technical committees. Each member body interested in a subject for which a technical committee has been
established has the right to be represented on that committee. International organizations, governmental and
non-governmental, in liaison with ISO, also take part in the work. ISO collaborates closely with the
International Electrotechnical Commission (IEC) on all matters of electrotechnical standardization.
International Standards are drafted in accordance with the rules given in the ISO/IEC Directives, Part 2.
The main task of technical committees is to prepare International Standards. Draft International Standards
adopted by the technical committees are circulated to the member bodies for voting. Publication as an
International Standard requires approval by at least 75 % of the member bodies casting a vote.
In exceptional circumstances, when a technical committee has collected data of a different kind from that
which is normally published as an International Standard (“state of the art”, for example), it may decide by a
simple majority vote of its participating members to publish a Technical Report. A Technical Report is entirely
informative in nature and does not have to be reviewed until the data it provides are considered to be no
longer valid or useful.
Attention is drawn to the possibility that some of the elements of this document may be the subject of patent
rights. ISO shall not be held responsible for identifying any or all such patent rights.
ISO/TR 13624-2 was prepared by Technical Committee ISO/TC 67, Materials, equipment and offshore
structures for petroleum, petrochemical and natural gas industries, Subcommittee SC 4, Drilling and
production equipment.
ISO/TR 13624 consists of the following parts, under the general title Petroleum and natural gas industries —
Drilling and production equipment:
⎯ Part 1: Design and operation of marine drilling riser equipment
⎯ Part 2: Deepwater drilling riser methodologies, operations, and integrity technical report
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ISO/TR 13624-2:2009(E)
Introduction
Since API RP 16Q was issued in 1993, hydrocarbon exploration in 1 200+ m (4 000+ ft) water depths has
increased significantly. As a consequence, the need was identified to update that code of practice to address
the issues particular to deepwater operations.
Under the auspices of the DeepStar programme, substantial work was commissioned during 1999 and 2000
by the DeepStar Drilling Committee 4502 and led to the development of Deepwater Drilling Riser
Methodologies, Operations, and Integrity Guidelines in February 2001. Several contractors participated in
these efforts. These guidelines were intended to supplement and update the existing API RP 16Q:1993 for
deepwater application. In a subsequent joint industry project and in collaboration with DeepStar and the API,
these guidelines were later supplemented with other identified revisions and technically edited by an API task
group to produce the revision of API RP 16Q:1993 as ISO 13624-1 and the API Technical Report TR1.
This Technical Report is a supplement to the revised API RP 16Q and provides guidance on various analysis
methodologies and operating practices.
NOTE The figures have been reproduced as provided by the Technical Committee and, in some cases, contain only
USC units.
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TECHNICAL REPORT ISO/TR 13624-2:2009(E)
Petroleum and natural gas industries — Drilling and production
equipment —
Part 2:
Deepwater drilling riser methodologies, operations, and
integrity technical report
1 Scope
This part of ISO 13624 pertains to mobile offshore drilling units that employ a subsea BOP stack deployed at
the seafloor. It is intended that the drilling riser analysis methodologies discussed in this part of ISO 13624 be
used and interpreted in the context of ISO 13624-1.
2 Normative references
The following referenced documents are indispensable for the application of this document. For dated
references, only the edition cited applies. For undated references, the latest edition of the referenced
document (including any amendments) applies.
ISO 13624-1:2009, Petroleum and natural gas industries — Drilling and production equipment —
Part 1: Design and operation of marine drilling riser equipment
API RP 16Q:1993, Design, Selection, Operation and Maintenance of Marine Drilling Riser Systems
3 Terms and definitions
For the purposes of this document, the following terms and definitions apply.
3.1
accumulator
〈BOP〉 pressure vessel charged with gas (e.g. nitrogen) over liquid and used to store hydraulic fluid under
pressure for operation of blowout preventers
3.2
accumulator
riser tensioner
pressure vessel charged with gas (e.g. nitrogen) over liquid that is pressurized on the gas side from the
tensioner high-pressure gas supply bottles and supplies high-pressure hydraulic fluid to energize the riser
tensioner cylinder
3.3
air-can buoyancy
tension applied to the riser string by the net buoyancy of an air chamber created by a closed-top, open-bottom
cylinder forming an air-filled annulus around the outside of the riser pipe
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ISO/TR 13624-2:2009(E)
3.4
annulus
space between two pipes, when one pipe is positioned inside the other
3.5
apparent weight
effective weight
submerged weight
riser weight in air minus buoyancy
NOTE Apparent weight is commonly referred to as weight in water, wet weight, submerged weight or effective weight.
3.6
auxiliary line
conduit (excluding choke-and-kill lines) attached to the outside of the riser main tube
EXAMPLE Hydraulic supply line, buoyancy-control line, mud-boost line.
3.7
ball joint
ball-and-socket assembly having a central through passage that has an internal diameter equal to or greater
than that of the riser and that may be positioned in the riser string to reduce local bending stresses
3.8
blowout
uncontrolled flow of well fluids from the well bore
3.9
blowout preventer
BOP
device attached immediately above the casing, which can be closed to shut in the well
3.10
blowout preventer
〈annular type〉 remotely controlled device that can form a seal in the annular space around any object in the
well bore or upon itself
NOTE Compression of a reinforced elastomer packing element by hydraulic pressure affects the seal.
3.11
BOP stack
assemblage of well-control equipment, including BOPs, spools, valves, hydraulic connectors and nipples, that
connects to the subsea wellhead
NOTE Common usage of this term sometimes includes the lower marine riser package (LMRP).
3.12
box
female member of a riser coupling, C&K line stab assembly or auxiliary line stab assembly
3.13
buoyancy-control line
auxiliary line dedicated to controlling, charging or discharging air-can buoyancy chambers
3.14
buoyancy modules
devices added to riser joints to reduce their apparent weight, thereby reducing riser top tension requirements
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ISO/TR 13624-2:2009(E)
3.15
choke-and-kill lines
C&K lines
kill line
external conduits arranged laterally along the riser pipe and used for circulation of fluids into and out of the
well bore to control well pressure
3.16
control pod
assembly of subsea valves and regulators that, when activated from the surface, directs hydraulic fluid
through special porting to operate BOP equipment
3.17
coupling
mechanical means of joining two sections of riser pipe in an end-to-end engagement
3.18
diverter
device attached to the wellhead or marine riser to close the vertical flow path and direct well flow away from
the drill floor and rig
3.19
drift-off
unplanned lateral move of a dynamically positioned vessel off its intended location relative to the wellhead,
generally caused by loss of either stationkeeping control or propulsion
3.20
drilling fluid
mud
water- or oil-based fluid circulated down the drillpipe into the well and back up to the rig for purposes including
containment of formation pressure, the removal of cuttings, bit lubrication and cooling, treating the wall of the
well and providing a transmission medium for well data
3.21
drive-off
unplanned move of a dynamically positioned vessel off location driven by the vessel's main propulsion or
stationkeeping thrusters
3.22
dynamic positioning
〈automatic stationkeeping〉 computerized means of maintaining a vessel on location by selectively driving
and/or directing thrusters
3.23
effective tension
axial tension that is calculated at any point along a riser in water considering only the top tension and the
apparent weight of the riser and its contents
NOTE See ISO 13624-1:2009, 5.4.3, and Sparks, 1984.
3.24
factory acceptance testing
FAT
testing by a manufacturer of a particular product to validate its conformance to performance specifications and
ratings
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ISO/TR 13624-2:2009(E)
3.25
fill valve
valve used to fill the riser with seawater to prevent riser collapse
3.26
fleet angle
〈marine riser〉 angle between the vertical axis and a riser tensioner line at the point where the line connects to
the telescopic joint
NOTE This angle changes with change in elevation of the vessel.
3.27
flex joint
steel and elastomer assembly having a central through-passage area equal to or greater than the riser bore
NOTE Flex joints are commonly placed at the bottom of the riser to reduce local bending stresses at the transition
from riser to lower marine riser package.
3.28
heave
vessel motion in the vertical direction
3.29
hot-spot stress
local peak stress
highest stress in the region or component under consideration, which causes no significant distortion and is
principally objectionable as a possible initiation site for a fatigue crack
NOTE These stresses are highly localized and occur at geometric discontinuities.
3.30
hydraulic connector
a mechanical device that is activated hydraulically and connects the BOP stack to the wellhead or the LMRP
to the BOP stack
3.31
hydraulic supply line
auxiliary line from the vessel to the subsea BOP stack that supplies control-system operating fluid to the
LMRP and BOP stack
3.32
jumper hose
flexible section of choke, kill or auxiliary line that provides a continuous flow around a flex/ball joint while
accommodating the angular motion at the flex/ball joint
3.33
lower marine riser package
LMRP
upper section of a two-section subsea BOP stack consisting of a hydraulic connector, annular BOP, ball/flex
joint, riser adapter, jumper hoses for the choke, kill and auxiliary lines, and subsea control pods
NOTE The LMRP lands in the top of the lower subsea BOP stack.
3.34
mud-boost line
auxiliary line that provides a supplementary fluid supply from the surface and injects it into the riser at the
LMRP to assist in the circulation of drill cuttings up the marine riser, when required
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ISO/TR 13624-2:2009(E)
3.35
pin
male member of a riser coupling or a choke, kill or auxiliary line stab assembly
3.36
pup joint
shorter-than-standard length riser joint
3.37
response amplitude operator
RAO
〈regular waves〉 ratio of a vessel's motion to the wave amplitude causing that motion and presented over a
range of wave periods
3.38
riser adapter
crossover between riser and flex/ball joint
3.39
riser disconnect
operation of unlatching of the riser connector to separate the riser and LMRP from the BOP stack
3.40
riser joint
section of the riser main tube having ends fitted with a box and pin and including choke, kill and (optional)
auxiliary lines and their support brackets
3.41
riser main tube
riser pipe
seamless or electric welded pipe that forms the principal conduit of the riser joint that guides the drill string
and contains the return fluid flow from the well
3.42
riser string
deployed assembly of riser joints
3.43
riser tensioner
means for providing and maintaining top tension on the deployed riser string to prevent buckling
3.44
riser tensioner ring
structural interface of the telescopic joint outer barrel and the riser tensioners
3.45
rotary kelly bushing
RKB
commonly used vertical reference from the drillfloor
3.46
slip joint
telescopic joint
riser joint having an inner barrel and an outer barrel with means of sealing in between
NOTE The inner and outer barrels of the telescopic joint move relative to each other to compensate for the required
change in the length of the riser string as the vessel experiences surge, sway and heave.
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ISO/TR 13624-2:2009(E)
3.47
stab
mating box and pin assembly that provides pressure-tight engagement of two pipe joints
NOTE 1 An external mechanism is usually used to keep the box and pin engaged.
NOTE 2 Riser joint choke-and-kill stabs are retained in the stab mode by the make-up of the riser coupling.
3.48
standard riser joint
joint of typical length for a particular drilling vessel's riser storage racks, the derrick V-door size, riser handling
equipment capacity or a particular riser purchase
3.49
strakes
helically wound appendages attached to the outside of the riser to suppress vortex-induced vibrations
3.50
stress amplification factor
SAF
ratio of the local peak alternating stress in a component (including welds) to the nominal alternating stress in
the pipe wall at the location of the component
NOTE This factor is used to account for the increase in the stresses caused by geometric stress amplifiers that occur
in riser components.
3.51
surge
vessel motion along the fore/aft axis
3.52
sway
vessel motion along the port/starboard axis
3.53
terminal fitting
connection between a rigid choke, kill or auxiliary line on a telescopic joint and its drape hose, effecting a
nominal 180° turn in flow direction
3.54
vortex-induced vibration
VIV
in-line and transverse oscillation of a riser in a current induced by the periodic shedding of vortices
3.55
wellhead connector
stack connector
hydraulically operated connector that joins the BOP stack to the subsea wellhead
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ISO/TR 13624-2:2009(E)
4 Abbreviated terms
BOP blowout preventer
DP dynamic positioning
DTL dynamic tension limit
ID internal diameter
LFJ lower flex joint
LMRP lower marine riser package
OD outside diameter
RAOs response amplitude operators
RKB rotary kelly bushing
ROV remotely operated vehicle
SAF stress amplification factor
TJ telescopic joint
UFJ upper flex joint
WSD working stress design
5 Coupled drilling riser/conductor analysis methodology and worked example
5.1 Coupled methodology
In a coupled analysis, the riser system analysed extends from the conductor up to the upper flex joint or ball
joint. Therefore, the vessel motions applied at the upper flex joint or ball joint along with the wave and current
loading can be used to predict the behaviour of the riser down to the displacements of the conductor in the soil
structure. This is a single-stage procedure. Figure 1 shows a schematic of a coupled model.
5.2 Decoupled methodology
The decoupled methodology is a two-stage procedure where two separate models are used to predict the
behaviour in the full riser system. The first model represents the riser system from the top of the subsea
BOP/LMRP to the upper flex joint or ball joint. The second model represents the riser from the conductor up to
the BOP/LMRP. The loads at the base of the first model (top of BOP/LMRP to upper flex joint or ball joint) are
then applied to the top of the second model to evaluate the behaviour of the conductor and riser at the
mudline. Figure 2 shows a schematic of a decoupled model.
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ISO/TR 13624-2:2009(E)
3
1
4
2
6
5
7
8
9
10
11
12
13
15
14
16
17
18
19
20
Key
1 drill deck (RKB) 11 riser buoyancy joints
2 heave/surge/sway 12 bare riser joints
3 surge/sway/pitch/roll 13 lower flex joint
4 heave/surge/sway
14 lower flex joint (articulation element)
5 upper flex joint 15 LMRP
6 upper flex joint (articulation element) 16 BOP
7 tensioner system modeled with spring/beam elements 17 mudline
or equivalent vertical tension
18 spring elements to model soil-structure
8 tensioners interaction
9 MWL 19 conductor/casing
10 slip joint 20 fixed in all degrees of freedom
Figure 1 — Drilling riser system configuration and coupled analysis model
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ISO/TR 13624-2:2009(E)
3
1
4
2
6
5
7
8
9
10
11
12
14
T
13
F
15
M
16
17
18
19
20
Key
1 drill deck (RKB) 11 riser buoyancy joints
2 heave/surge/sway 12 bare riser joints
3 surge/sway/pitch/roll 13 lower flex joint
4 heave/surge/sway 14 lower flex joint (articulation element)
5 upper flex joint 15 LMRP
6 upper flex joint (articulation element) 16 BOP
7 tensioner system modeled with spring/beam elements 17 mudline
or equivalent vertical tension
18 spring elements to model soil-structure
8 tensioners interaction
9 MWL 19 conductor/casing
10 slip joint 20 fixed in all degrees of freedom
Figure 2 — Drilling riser system configuration and decoupled analysis models
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ISO/TR 13624-2:2009(E)
5.3 Analysis considerations
API RP 2RD, Section 6, and API RP 17B, Section 8, discuss in detail the analysis considerations relevant to
riser systems, which are also appropriate to drilling risers. The two key issues of relevance to this technical
note are as follows:
a) solution of equations of motion (frequency-domain or time-domain solution);
b) dynamic response evaluation (design-wave or design-storm methodology).
Frequency-domain analysis is appropriate when it is known that the effects of tension coupling are small and
that there are no other nonlinearities significantly affecting the riser response. It is often used for fatigue
analysis where the loads are less extreme and response is nearly linear. Time-domain analysis is used when
more accurate representation of nonlinear behaviour is important. This applies particularly to the analysis of
nonlinear conductor/soil interaction behaviour, but also to weak-point and disconnect analyses, where
nonlinearities are important.
The objective in performing dynamic analyses is to predict the maximum or extreme response of the riser
system. The two approaches commonly used for this purpose are design-wave and design-storm analyses.
The design-wave (or regular-wave) approach is based on a deterministic sea state description of the wave
environment using a single wave height and period to model the sea state. These parameters are derived
using wave statistics or simple physical considerations. The advantage of the approach is that the response
calculation is straightforward, periodic input generally giving periodic output with no further requirement for
statistical post-processing. The limitation of the design-wave approach is that its use is uncertain in systems
whose response is strongly dependent on frequency. In such situations, the design-storm approach can be
necessary.
The design-storm or irregular-sea approach is based on a stochastic description of the wave environment.
The sea state is modeled as a wave spectrum with energy distributed over a range of frequencies. The most
common spectra used are the Pierson-Moskowitz (fully developed sea) and the JONSWAP (developing sea)
spectra; see Chakrabarti, 1987. The response, in this case, is also stochastic, and statistical post-processing
is necessary to identify the design value of the response. Normally, a 3 h design-storm duration should be
considered. The extreme response for the design storm should be found by using a recognized most-
probable-maximum extrapolation technique.
All dynamic-analysis results presented in this part of ISO 13624 were generated from time-domain solutions of
regular-wave analyses.
5.4 Model development
5.4.1 Overview
A schematic configuration of a typical drilling riser system is presented in Figure 1 along with a coupled
riser/BOP/conductor/casing tensioned beam model, which is used to analyse the system. A drilling riser
system can be typically broken down into the following components:
a) drilling system;
b) tensioner system;
c) slip joint;
d) upper and lower flex joint;
e) drilling riser;
f) LMRP/BOP stack;
g) conductor/casing.
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ISO/TR 13624-2:2009(E)
Table 1 presents a list of important parameters associated with each of the components a) to g) above. These
parameters represent the basic building blocks from which the drilling riser model is constructed.
The methods for modeling the components of each drilling riser system are discussed in 5.4.2 to 5.4.8.
Table 1 — Input parameters for a drilling riser analysis model
System component Input parameter
Drilling vessel Location of vessel centre of gravity
Vessel response amplitude operators (RAOs)
Vessel draft
Vertical distance from upper flex joint to drill floor
Vertical distance from keel to the drill floor
Tensioner system Number of tensioners
Maximum available tension per tensioner
Tensioner fleet angle and efficiency
Tensioner length and stiffness
Slip joint Collapsed length
Fully extended length
Outer and inner barrel outer diameter and wall thickness
Outer and inner barrel air weight and submerged weight
Flex joints Rotational stiffness of the flex joint as a function of cocking angle subtended
Bare riser joints Outer diameter and wall thickness of the joint and any choke-and-kill lines and/or auxiliary
lines attached to the riser joint
Weight in air and weight in water of the joint and any choke-and-kill lines and/or auxiliary
lines attached to the riser joint
Length of the riser joint
Yield strength of the material
Failure capacity of riser joint bolted flange/screwed connector
Buoyancy riser joints Weight in air of the buoyancy joints for relevant water depths
Upthrust of the buoyancy joints for relevant water depths
Internal fluid Density of the drilling mud
LMRP/BOP stack Equivalent outer and inner diameters of LMRP/BOP that simulate the bending stiffness and
axial stiffness of these components
Weight in air and weight in water of LMRP/BOP
Failure capacities of the LMRP/BOP bolted flanges and hydraulic connectors
Conductor/casing Outer and inner diameters of the conductor pipe and casing sections
Lengths of the conductor pipe and casing sections
Height of conductor/casing above seabed
Assumed level of scour below the seabed
Yield strength of the conductor/casing pipe material
Structu
...
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