OTC Paper 14263 - Drilling RP 16Q Paper (Master)

Copyright 2002, Offshore Technology Conference This paper was prepared for presentation at the 2002 Offshore Technology Conference held in Houston, Texas U.S.A., 6–9 May 2002. This paper was selected for presentation by the OTC Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Offshore Technology Conference and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Offshore Technology Conference or its officers. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Offshore Technology Conference is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of where and by whom the paper was presented.

Abstract Since the Recommended Practice for Design, Selection, Operation and Maintenance of Marine Drilling Riser Systems (API RP 16Q) was first issued in 1993, the focus on drilling operations in deep water has significantly increased. With that evolution comes the need to reassess the way we design and operate such risers to ensure the safety and integrity of drilling risers designed and operated in deepwater environments. Under the auspices of the DeepStar program, substantial work was commissioned in 1999 that lead to the drafting of guidelines to address several issues not addressed within the existing RP. In a subsequent Joint Industry Project sponsored by DeepStar and in collaboration with API, MCS International has brought forward this work to produce a major update of RP16Q and an associated Technical Report (API 16TR1). This paper describes the contents of the revised standard, in terms of the substantive changes from the 1st edition and the significant additions drafted to broaden its applicability to deepwater drilling risers.

The revision of API RP 16Q, which is proposed for submission as an ISO Standard, incorporates the new guidelines developed under DeepStar and supplements this with additional guidelines to address other issues. Guidelines developed for DeepStar have been incorporated in the areas of riser analysis methodology, riser operations and riser integrity.

Several additions to the existing RP16Q text cover analysis methodology associated with soil structure modelling, coupled analysis, drift-off analysis, weak point analysis and other issues. Additional guidelines have been included which relate to operational procedures and riser integrity issues and these are described by the paper.

This first substantial revision of API RP 16Q provides the offshore industry with an improved recommended practice

that has been substantially extended to address issues associated with the design and operation of deepwater marine drilling risers.

Background DeepStar Phase IV Under the auspices of the DeepStar program, substantial work was commissioned during 1999 and 2000 by the DeepStar Drilling Committee 4502. The work was designed to address several issues associated with the design and operation of deepwater drilling risers that were not explicitly dealt with in the existing text of API RP16Q.

The deliverables of this work were a set of guidelines and worked examples that provided sufficient detail to supplement the existing text of API RP16Q and provide additional guidance for deepwater drilling in water depths up to 10,000ft.

This work, delivered by several contractors, lead to the drafting of “Deepwater Drilling Riser Methodologies, Operations and Integrity Guidelines” in February 2001 as an integrated collation of all of the Phase IV DeepStar work.

The authors and the other contractors produced and issued several documents to DeepStar that supplement and sometimes complement the text of the existing API Drilling Riser Recommended Practice [RP16Q]. These guidelines were intended to ‘modernize’ the existing RP and bring it into the current era of ultra -deepwater drilling. A breakdown of the workscopes associated with the drafting of these guidelines is presented in Figure 1. RP16Q JIP and DeepStar Phase V In early 2001, a JIP was initiated [1], under the sponsorship of DeepStar Phase V, to integrate into the existing RP16Q all of the deliverables of DeepStar Phase IV. In addition to that work, additional guidelines were developed to address some other issues, such as drilling riser hang-off, which had not been adequately addressed either by the existing RP16Q or the work of DeepStar Phase IV. The deliverable of this work is to issue, in a format suitable for ISO balloting, an updated text of API RP16Q as an ISO standard.

New Codes of Practice Introduction to New Codes The deepwater drilling riser guidelines produced by DeepStar Phase IV, especially some of

OTC 14263

New Revision of Drilling Riser Recommended Practice (API RP 16Q) Kieran Kavanagh/MCS International, Michel Dib/MCS International, Erin Balch/MCS International, Paul Stanton/CSOAEI

2 K. KAVANAGH, M. DIB, E. BALCH, P. STANTON OTC 14263

the analysis methodologies and worked examples, represented more material than could be practically included in a single revision of API RP16Q. Furthermore, the update of RP16Q should more appropriately focus on recommended practice, while other optional practice, guidelines and worked examples would more usefully lie in a separate supporting document, to be referenced in conjunction with the updated recommended practice.

For this reason, a decision was made by the RP 16Q Steering Committee to release two separate documents, one updated recommended practice and another set of supporting guidelines and worked examples. These two documents are: 1. An update of API RP16Q, to be balloted for release

within API as 2nd Edition of this document. In parallel with this effort, it is also proposed to seek release of this document within the ISO process as ISO 13624.

2. A separate API Technical Report (API 16TR1), containing methodologies, worked examples and other supplementary material to be referenced in conjunction with the new RP, but to be balloted for release as an API Technical Report (API 16TR1) rather than an ISO code of practice.

Summary of New Codes Changes Several editorial changes to the existing RP16Q text were developed to provide guidelines on several issues relevant to the analysis, operation and integrity management of deepwater drilling risers which were not explicitly addressed in the existing text of RP16Q. Among these were guidelines associated with the following riser Analysis issues:

i.) Conductor Casing Soil-Structure Modeling ii.) Coupled Drilling Riser / Conductor Analysis iii.) Drilling Riser Drift Off Analysis iv.) Drilling Weak Point Analysis v.) Riser Recoil Analysis vi.) Issues Related to Operating in High Currents vii.) Hangoff Analysis guidelines Also included is an updated body of text relating to riser

Operations: viii.) Deepwater Drilling Riser Operations Guideline Integrity was also an issue addressed by editorial changes

and the introduction of: ix.) Deepwater Drilling Riser System Integrity

Guidelines Among these editorial changes, items iii), vi), vii), viii)

and ix) deal with issues which are considered to be directly relevant to deepwater riser recommended practice. For this reason, these guidelines have been incorporated directly into the update of the existing API RP16Q (ISO 13624) (Document 1 of the previous sub-section). Items i), ii), iv) and v) represent more general guidance and optional analyses, such as Weak Point and Recoil analysis, which are not typically performed for all planned drilling activities. Although general information can be found in the RP16Q / ISO 13624, guidelines and worked examples associated with these issues are presented in the supporting Technical Report (API 16TR1) (Document 2 of the previous

sub-section) and referenced in the update of RP16Q. On the issue of design requirements, the new draft API

RP16Q (ISO 13624) does not specify any changes in allowable stress utilizations in the drilling riser. Nor does it recommend changes in the allowable mean and maximum allowable flexjoint angles. Contents of Revised API RP 16Q Documents

Introduction This section presents the draft revisions to the API RP16Q Documents in terms of three primary strands associated with their update:

• Analysis Guidelines • Operations Guidelines • Integrity Guidelines The Table of contents of the 1st Edition of RP16Q is

presented for information in Figure 2. The revised tables of contents of the updated draft API RP16Q / ISO 13624 and the API Technical Report (API 16TR1), provided in Figure 3 and Figure 4 respectively, illustrate the extent of the additional guidelines provided by these two documents and the expansion of their scope to include issues associated with deepwater drilling.

Drilling Riser Analysis Guidelines Introduction The following section provides a brief outline of the additional Analysis Guidelines which have been introduced to RP16Q (ISO 13624) and the supporting Technical Report (API 16TR1). More complete guidance is presented in the text of these documents. Coupled Modeling Coupled modeling is the modeling of the entire system including the vessel (modeled implicitly), the slip joint, the flex joints, the drilling riser, the LMRP/BOP, the conductor casing and the soil model. Figure 5 shows a typical coupled model with its boundary conditions.

Coupled analysis is a more appropriate method to use where the response of the conductor/casing is a key output as in the design of the conductor/casing system. This type of analysis is also beneficial in weak point analysis and drift-off/drive-off analysis. It is typically performed in a time domain in order to realistically simulate the non-linear material properties of the soil. It also gives a better picture of the riser response to the vessel drift rate.

Figure 6 illustrates the benefits of such coupled modeling over the alternative decoupled model in terms of the accuracy of the angle predicted at the lower flex joint. Soil Structure Modeling The ability to be able to predict the behavior of laterally loaded conductor casing embedded in the seabed is an important consideration in the design of conductor casing systems and in the prediction of lower flexjoint angle and wellhead bending moments. If the soil immediately below the mudline has low strength, as is frequently the case, little resistance is provided against lateral deflection in this region and the area of highest bending of the

OTC 14263 NEW REVISION OF DRILLING RISER RECOMMENDED PRACTICE (API RP 16Q) 3

structural casing can occur some distance below the mudline. For this reason, the characterization of lateral resistance of the soil near the mudline is an important input to a reliable structural model of a coupled casing-riser system. Under lateral loading, soils typically behave as a nonlinear material which makes it necessary to relate soil resistance to conductor casing lateral deformation. This is achieved by constructing lateral soil resistance-deflection (p-y) curves, with the ordinate of these curves being soil resistance per unit length, p and the abscissa being lateral deflection, y.

The loading on a typical conductor casing is illustrated in Figure 7. The analysis of such a problem may be accomplished by structural analysis of the casing structure using nonlinear springs to model the p-y behavior of the soil and by the solution of the following equilibrium equation:

pdx

ydEI =

4

4

Where y= casing deflection x= length along casing EI= equivalent bending

stiffness of casing system p= soil resistance per unit length

Using techniques of numerical integration, this equation can be solved if the casing geometry and soil stiffness boundary conditions are known, typically in terms of a family of p-y curves developed for the soil. These p-y curves, which represent the increasing nonlinear soil stiffness with depth, are typically based on empirical formulations proposed by Matlock et al. (9), Reece (10) and O’Neill et al. (11) for soft clay, stiff clay and sand respectively. The draft API Technical Report (API 16TR1) provides guidance on the derivation of these curves.

Drift-Off / Drive-Off Analysis Drift-Off / Drive-Off analysis is the analysis of an uncontrolled vessel excursion due to power failure or failure of the positioning system to operate properly. The purpose of this type of analysis is to determine what the disconnection criteria are and when to initiate procedures to allow for a safe disconnection of the drilling riser. This is typically a deepwater issue as well as a driller decision issue.

The drift-off / drive-off analysis can be broken down into three main parts:

• Evaluation Criteria • Analysis Methodology • Determination of Disconnection Point

In the evaluation criteria stage, it is important to first identify the system limits, such as:

• Stroke-out of slip joint • Overstressing the drilling riser • Riser clashing with the moonpool • Overloading the flex joint • Overloading the connectors/flanges or

BOP/LMRP • Exceeding wellhead capacity

• Overstressing the conductor casing The object is to insure no design criteria are exceeded.

Use the allowable loads, stresses, and deflections that are inherent to the system. Figure 8 shows a graphical representation of the drift-off/ drive-off system limits.

The analysis methodology is explained in Figure 9. The drift-off disconnect point is the lowest allowable disconnect offset for all component limits.

The disconnection initiation time is evaluated from the equation:

TINIT = TDISC – TLAG – TDYN

Where TDISC= Disconnect time TLAG= lag between initiating disconnect and

disconnect TDYN= Allowance for dynamics (if not already

considered in analysis). Weak Point Analysis The main object of a weak point analysis is to determine the weakest point of the riser system assuming the inability to disconnect the riser. Because it is typically an equipment selection issue, for example guiding the selection of structural casing size or wellhead moment capacity, it is frequently an analysis performed by or on behalf of operators. Weak point analysis can be described in terms of the following issues:

• Potential Weak Points & Criteria • Methodology • Weak Point Location and Design Issues

Weak point analysis is similar to drift-off / drive-off analysis in that the same system limits are monitored. The failure of any system of the riser is based on yield strength or ultimate strength. This type of analysis can contribute to the structural design or selection of component capacities.

The analysis methodology is explained in Figure 10, and Figure 11 and Figure 12 show some typical graphical results of a weak point analysis.

The weak point should be located at a point that does not compromise the systems integrity. For example, a desired weak point could be a bolted flange between two system components such as the flex joint, stress joint, or LMRP. If it is discovered that the location of the weak point may compromise the system's integrity (e.g. location in the structural casing), the option exists to re-design the component in an effort to relocate the weak point to a more favourable location (e.g. the LMRP).

One difficulty associated with weak point analysis lies in determining the ultimate capacity of the system components as an input to the analysis. The estimation of the capacity of some comp onents typically requires input from riser component manufacturers.

High Current Environment The use of a marine drilling riser


in currents exceeding about two knots has the potential to cause operational difficulties. These problems include high drag loads on the riser, vessel and mooring lines, and the potential that the riser might experience high bending stresses and vortex induced vibrations (VIV).

The high drag loads can cause increased mooring line tension, higher vessel offset, and in turn can cause increased riser lateral displacement and lower flex joint angles. The high currents also have an impact on open water operations such as running the conductor casing strings and running and retrieving the riser and BOP.

The limiting environmental criteria for running and retrieval operations should be determined by, as a minimum, VIV analysis and lateral deflection analysis.

There are several different ways to mitigate VIV problems. These include the use of fairings and strakes. Although both of thes e are effective in VIV supression, they have operational issues that might be cumbersome. It has also been shown that staggering buoyed joints with bare joints can reduce the effects of VIV.

The analytical prediction and description of vortex inducted ris er vibration is very complex. It is dependent on the interaction of the current velocity and the lateral vibration modes of the riser which are affected by its geometry, mass, contents, and tension. The modes of excitation of the riser depend on the current profile with respect to that mode.

The maximum current condition may not produce the worst fatigue loading. The velocity and distribution associated with the maximum current may be such that no modes are excited, or that the duration of that current is such that little fatigue loading is induced. Lower current velocities may have a more unfavorable distribution and duration that may control fatigue life.

Recoil Analysis Riser recoil is a complex dynamic process in which, upon disconnection of the riser at the BOP, the riser is forced upwards. This can cause compression in the riser itself as well as rope slack in wire tensioners, or jump out / compression in direct acting tensioners. The sudden recoil of the system is caused by the potential energy stored in the riser and the tensioner system.

Simple calculations cannot sufficiently describe this complex process, particularly where complex control systems and high overpulls are involved. Reliable simulation typically requires analytical tools that have been developed specifically for this purpose.

Hang-Off Analysis Hang-off analysis consists of analyzing a drilling riser when it is supported by the vessel but disconnected from the wellhead. This includes determining operating limits for running/pulling of the riser, the feasibility of a hard or soft hang-off, and the determination of the number of bare riser joints at the bottom of the riser string.

A hard hang-off is when the telescopic joint is collapsed and the riser is supported by a fixed connection, typically in the riser spider, and moves with the vessel. A soft hang-off is when the riser is supported by the tensioners and motion

compensators and acts much like a soft spring. The key issues for hang-off analysis are lateral loads and

axia l response of the riser. Modeling guidelines for all hang-off scenarios are presented in detail in the RP16Q / ISO 13624 document.

Drilling Riser Operations Guidelines Introduction The riser operations section is expanded to provide additional guidance and examples on running and retrieval operations for normal and emergency situations. Riser Operations Information Systems Emphasis is placed on the need to regularly monitor key parameters: top tension and mud density, flex joint and ball joint angles, vessel position, wave height and current velocities, for the purpose of accurately logging operating history. These records provide a background of experience to apply for future operations and to provide a basis for determining the need for riser inspections and maintenance.

The need for accurately forecasting environmental conditions is also stated since operations in deep waters require more time to execute.

Riser Running and Retrieval Some remarks are made about when to use an intermediate flex joint, about the need to monitor hook load variations, and about the importance of properly spacing-out the riser joints (to allow for vessel drift while maintaining adequate telescopic joint stroke for the recoil system).

Warning notes are given about the dangers of long periods of riser hangoff and about the riser clashing with the vessel in high surface currents and waves especially while the BOP stack is passing in the wave zone, and recommendation is given for establishing wave and surface current limits, or operating envelope. An example of operating envelope is provided. The controlled drift-off technique is described for DP vessels as a means of deployment when surface current are high.

Avoiding sudden load transfer to the tensioners as the BOP is landed or disconnected should be considered.

The soft hangoff method is presented as an alternate means for hanging off the riser in case a storm suddenly encounters the vessel with little or no time to pull the riser. The benefits gained, over hard hangoff, could be substantial reduction in reaction loads at the vessel, and riser stress variations. The equipment used to enable soft hangoff is the tensioner system only or a combined support system of tensioner and motion compensator, depending on whether or not the BOP is in the riser. Typical operating procedures are provided for soft hangoff. Installed Riser Operations Emphasis is placed on the need to maintain top tension above the API minimum, by a safe margin, especially for high mud weights, to prevent damage to the riser from load variations that might otherwise allow the tension to fall below the minimum. Environmental conditions for which operations should be suspended must be determined


and specified in the riser operations manual. Also, additional riser tension may be required for increased offset to maintain acceptable lower flex joint (LFJ) differential angle.

Generally, drilling operations are to be suspended when the lower flex joint rotation reaches 2 to 4 degrees, because contact forces between the drillstring and the flex joint/wellhead may cause extreme wear and other damage. LFJ angle is primarily controlled by adjustment in top tension and vessel position. Wear at the LFJ is also dependent on the drillstring tension as it determines the normal force on the LFJ. A normal force less than 2000 lb is generally acceptable. Higher normal forces can cause moderate to severe wear. Among the other factors affecting wear are tool joint abrasiveness, drilling rate, and drillstring rotary speed. The LFJ differential angle limitation on drilling operations should be made based on the specific operation in progress, well depth, drillstring configuration, and other factors. A differential angle of 1 degree or less is typically maintained for normal drilling operations.

Riser survival limits are usually expressed as the maximum flex joint angles beyond which damage occurs to BOP or to the wellhead. The survival limit can be expressed in terms of wave height, current speed, and vessel offsets, which cause the flex joint limit to exceed safe values.

Riser disconnection should take place only after careful evaluation of all alternatives because of the possible consequences to the vessel and the well. Many hours of tripping may be required to secure the well, except in emergencies. Riser disconnect is to be executed when the angle is likely to exceed 6 to 10 degrees, after the well is secured.

Soft hang-off or hard hang-off can be used after the riser disconnects. Analysis is typically required to investigate the feasibility or relative advantage of each method. A standard disconnect procedure is presented for unlatching the LMRP and going into soft hang-off.

Conductor and Casing Installation Running the

conductor is also addressed. Large displacements with possible moonpool clashing and bending stresses can result during this operation, especially when the casing is rigidly hung in the slips. Therefore, the limiting current and wave environments should be identified. An example is provided demonstrating three configurations that require analysis: wave zone, near bottom, and casing installed. The example suggests that the most critical part of the operation is when the conductor is running through the wave zone.

The main issues encountered with running the 20-inch casing are discussed; these are: loading on the casing body when held in the slips, loading on the work string when held in the slips and bending of the work string at the connection to the casing. An example is presented showing four configurations for the casing running operation that are recommended for analysis. This analysis provides guidance in determining the limiting conditions for successful operations, provided representative current profiles and accurate running string characteristics are used for the analyses.

The controlled drift technique of a DP vessel can be used to facilitate running the conductor/casing, by allowing the vessel to drift with the current, in a controlled manner, from and upstream position, while deploying the conductor or the casing. When the conductor/casing reaches a depth where currents are lower, the vessel drift may be discontinued, to allow for installation of the conductor or the casing in the borehole. This technique can be analyzed with currents and waves to identify the operating envelope for this activity.

Tropical Disturbance Evacuation When operating in sites where a tropical disturbance may occur, a reliable source for storm tracking and weather prediction is necessary. Periodic forecasts should report the predicted path of the tropical disturbance, the estimated storm arrival time, and the predicted weather (wind, waves, and current) as the storm approaches. The frequency of the weather reports is to increase as the storm approaches the rig. If such a storm is determined to be on a course that intersects the rig, evacuation procedures are to be implemented. A typical evacuation sequence is provided.

Emergency Disconnect: Emergency disconnect (ED) is

executed when the vessel loses its ability to maintain position, either because of failure in the dynamic positioning system or because of multiple mooring line failures. In this case large vessel offsets can cause stroking out of the telescopic joint or the tensioners and subsequent damage to the vessel and the riser. Severe weather can also require emergency disconnect. ED pre-planned procedures are specific to the rig, the operation in progress, and the tubulars in the BOP. The rig should be equipped with an anti-recoil system to absorb the impact from the sudden force imbalance in the riser. It should be performed within 30 to 50 seconds to prevent serious damage to the vessel, riser or well system. The limiting vessel offset for ED defines the red watch limit, or circle, which is usually determined from riser analysis. Stress in the casing, lower flex joint differential angle, subsea wellhead system load capacities and riser stress are some of the criteria that can determine the red limit. The vessel will also have other limits such as one for normal operations called the blue limit or circle, as well as an intermediate one: yellow circle. These circles are an important part of the ED procedure.

Moored Vessel Considerations The station keeping ability of the rig must be analyzed and results provided as input to riser analysis to determine potential operational limitations. Rig position is to be monitored continuously to minimize lower flex joint angles, and that usually requires frequent mooring line adjustments. The riser should be evaluated for a minor mooring failure event, such as slipping of one anchor. Drilling Riser Integrity Guidelines Basis of Inspection Requirements Riser inspection for the purpose of detecting, quantifying and evaluating the effect of deterioration on the riser’s fitness for service, is recommended after fabrication, first use, installation/retrieval, and at periodic


intervals. Deterioration can result from fatigue damage accumulation, wear from drill string rotation (key seating), impact loads (during handling, running, and retrieval), and corrosion. The requirements for post-fabrication include through-thickness crack detection, surface crack detection, thickness measurement, and ovality. The requirements for first use are determined by the manufacturer. During installation/retrieval and periodically visual inspection is required. For shallow water existing inspection programs are adequate. For longer term deep water operations, usual inspection methods might be insufficient due to the increased demand on the riser from higher tensions, larger curvatures, longer and heavier joints, greater internal and external pressures, and vortex-induced vibrations from high currents. For deep water drilling, a preliminary evaluation of conditions should be conducted, and a strategy for in-service inspection developed. Preliminary evaluation involves examining the previous inspection records and operating history, gathering site-specific environmental data, and performing fatigue analysis for each well. In-service inspection is presented next. Maintenance After Riser Retrieval After retrieval, the riser is to be rinsed with fresh water, visually inspected, serviced and stored according to manufacturer’s recommendations. Tensioners are to be inspected per manufacturer’s recommendations: sheave grooves are to be checked for wear, piping for leaks, exposed rods for lubrication, and wire rope systems for broken strands. Of particular importance is the condition of the wire ropes at the contact points with the sheaves. Wires may need to be cut and slipped to change wear points. Manufacturer's requirements should also be followed for inspecting and servicing the telescopic joint. The inner barrel should be locked to the outer barrel during handling. Inspection guidance is provided for the flex joints. Transportation Handling and Storage Handling riser joints should be done for individual joints with the pin ends covered and the couplings lubricated. Joints with foam buoyancy should be handled with extra care especially if cranes are used to move them instead of automatic handling equipment, and slings should be capable of lifting the telescopic joint which could be substantially heavier than the other riser joints. Also peripheral lines should not be used as sling attachments. Stacking bare joints should be done using support shims under the bottom layer and between successive layers. Unsupported sections of peripheral lines should not be subjected to the weight of other joints. Joints with syntactic foam may be stacked without shims. Guidance is also provided for rig racks storage and land-base storage. Scheduled Field Inspection and Maintenance Field inspection and maintenance are to be scheduled regularly and performed for all riser components. Inspection procedures are to be documented in the riser operating manual and should include visual inspection for corrosion, cracks, and wear in the riser joints. NDE methods such as magnetic particle inspection or liquid penetrant are to be applied to critical areas for cracks.

Ultrasound or its equivalent is to be used to check the main tube wall thickness. These tools are suitable for onshore inspection and may not be practical in the field. Accordingly, alternative simpler techniques can be used offshore as screening tools such as: calipers, intelligent pigging, reflected wave type methods, and fatigue fuses, for identifying suspect components, which in turn can be singled out for conventional detailed inspection onshore.

Acceptance criteria should be set by agreement between operator and contractor. Inspections are to be performed after abnormal conditions, but in principle at least once a year. As a minimum the frequency for inspection of all joints should be defined and a shorter interval specified for those joints subjected to highest levels of fatigue damage, as determined by riser analysis, and joints near the top and base of the riser which are subjected to the greatest level of wear. Records should be kept of any adverse findings. Remedial action should be in accordance with the manufacturer’s recommendation. Welding is generally not allowed.

Guidance on Components to be Inspected For the riser joints, all welds deserve periodic inspection for fatigue cracks including welds between couplings and the main tube, and welds at mid-length of the main riser pipe. Wall thickness measurements should be made to determine any sign of wear or corrosion. Choke and kill lines also are to be inspected, especially at their welded connections since they can be subject to vortex induced vibrations, and may assist the main tube in carrying a fraction of the load. The base of the slip joint may experience fatigue cracking, as well as at the top where choke and kill line off-takes are mounted and at the interface with the tension ring. The upper barrel is also susceptible to wear. For the BOP stack, wear in the LMRP near the flex joint should be inspected. The BOP is generally not subject to fatigue unless welding is used to modify the BOP for accommodating completions equipment.

Acceptance Criteria Wall thickness reduction is to be evaluated against the tolerances specified in API 5L which is usually ±12.5%. This can be due to wear from drillstring rotation and from corrosion. Three types of wall thickness reductions are addressed: localized loss where the pressure resistance of the joint is to be reassessed, but not its tensile and bending capacity. The second is longitudinal loss which may affect the pressure resistance, but usually will not impact the tensile and bending capacities. The third is circumferential loss that may affect pressure resistance, tensile and bending strengths, as well as fatigue endurance; therefore, the minimum wall thickness should not be less than the nominal wall thickness less the API or the manufacturer’s tolerance. When dimensions fall outside of tolerance limits, the joint is to be de-rated and its use limited to the middle section of the riser.

Fatigue cracks may be repaired by grinding and re-welding; however, the crack may signal that the joint has exhausted its service lifetime, and that a complete re-


fabrication will be required by removal of all welds and heat-affected zones, and re-welding.

For pipe sections considered imperfect due to ovality, collapse criteria may be used to assess the external pressure resistance. For dented pipes, buckle propagation criteria may be checked. Operational Records for Riser Components A two-level approach is outlined for recording riser usage. The first logging approach is based on “usage only” which requires a relatively small data collection effort. Inspection is based on total time in service of each joint, joint position, and riser configuration (connected and hang-off). The second logging approach is based on “usage and conditions”, where the scope of the “usage only” logging is increased to included severity of the operating conditions. Forward Plan for Release of New Codes

The status of the new codes at the time of drafting this

paper is as follows:

1. The draft update of API RP16Q is currently being released to the joint DeepStar / API Drilling Riser Task Group Steering Committee in Draft Rev.C. The JIP plans one further revision after that draft. Provision has then been made for submission of the document to the API review and approval process for release as API RP16Q (2nd Edition). In a parallel effort, the current plan is also to seek approval of the document within the ISO process as ISO 13624.

2. The current plan for publishing the Technical Report (API 16TR1) containing methodologies and worked examples is to finalize its text and put it for direct balloting within the API approval process. This API Technical Report (API 16TR1) would not be submitted to the ISO approval process.

References 1) JIP Proposal “RP16Q JIP”, MCS International, submitted for

sponsorship to DeepStar, 2001. 2) "Conductor Casing Soil-Structure Modeling Methodology",

MCS International Document No. 1-1-4-111/TN02 Rev 2, February, 2000.

3) "Coupled Drilling Riser/Conductor Analysis Methodology", MCS International Document No. 1-1-4-111/TN01 Rev 2, February, 2000.

4) "Drilling Riser Drift-Off and Weak Point Analysis Methodology", MCS International Document No. 1-1-4-113/TN01 Rev 2, April, 2000.

5) "Drilling Riser System Integrity Guidelines", 2H Offshore, Rev1, November 2000.

6 "Deepwater Drilling Riser Operations Guidelines", Det Norske Veritas, April 2000.

7) “Petroleum and natural gas industries – Drilling and production equipment – Design and operation of marine drilling riser equipment”, API RP16Q, November 1993.

8) "Methodology of Operating/Analysis and Integrity of Drilling Riser Systems to 10,000 ft – Riser Recoil Following Emergency

Disconnect", Stress Engineering Document No. 1-99-6442-MWS, February 2000.

10) Matlock, H. (1970), Correlations for Design of Laterally loaded Piles in Soft Clay, OTC 1204.

11) Reece, L.C., and Cox, W.R. (1975), Field Testing and Analysis of Laterally Loaded Piles in Stiff Clay, OTC 2312.

9) O'Neill, M.W., and Murchinson, J.M. (1983), An Evaluation of p-y Relationships in Sands, a report to the American Petroleum Institute.

Acknowledgements The authors pay tribute to the contracting companies and individuals who contributed to the work commissioned by DeepStar Phase IV which fed into this work, including DNV, Riley Goldsmith, Stress Engineering, Atlantia Offshore, 2H, Southwest Research and their colleagues at MCS International.

The authors also acknowledge the support of DeepStar, especially the DeepStar 5502 and 4502 committee members Dave Bacon, who facilitated the RP16Q JIP, and Bill Todd, Jim Brekke and Shaddy Hanna who coordinated the original work of contributing contractors. Thanks also to Riddle Steddum for his contribution associated with high current environment. Tribute is also paid to those companies who, as participants of DeepStar Phases IV and V, were party to commissioning and sponsoring the development of new Drilling Riser Guidelines and allowing them to contribute to the development and proposed update of RP16Q.

Finally, appreciation is expressed to David Tannich, the chairman of API Subcommittee 16, to the members of the API Drilling Riser Task Group, and to other members of the steering committee of the RP16Q JIP, who contributed through their guidance, document review and comment to the development of these draft standards.


DeepStar Phase IV

Workscope Supplementary Guidelines Contractor

Analysis Methodologies

Conductor Casing Soil- Structure Modeling Methodology

MCS1

Coupled Drilling Riser / Conductor Analysis Methodology

MCS1

Drilling Riser Drift Off Analysis Methodology

MCS1

Drilling Weak Point Analysis Methodology

MCS1

Riser Recoil Analysis Methodology

SES1

Drilling Riser VIV Nomograph AOL1

Operations Deepwater Drilling Riser Operations Guideline

DNV & RG1

Integrity Deepwater Drilling Riser System Integrity Guidelines

2H & SWR1

Note: 1. The following abbreviations are used for the contributing companies: MCS: MCS International; SES: Stress Engineering, AOL: Atlantia Offshore; DNV: Det Norske Veritas; 2H: 2H Offshore; SWR, Southwest Research; RG, Riley Goldsmith.

Figure 1 Methodology Guidelines

Figure 2 Table of Contents of API RP16Q (1st Edition)


FOREWORD

IINNTTRROO DDUUCCTTIIOONN

SECTION 1: SCOPE

SECTION 2: NORMATIVE REFERENCES

SECTION 3: TERMS, DEFINITIONS AND ABBREVIATIONS

SECTION 4: COMPONENT FUNCTION And SELECTION

SECTION 5: RISER RESPONSE ANALYSIS

55..11 GGeenneerraall CCoonnssiiddeerraattiioonnss 55..22 RRiisseerr AAnnaallyyssiiss PPrroocceedduurreess 55..33 DDeessiiggnn aanndd OOppeerraattiinngg LLiimmiittss 55..44 RRiisseerr AAnnaallyyssiiss 55..55 CCoouupplleedd AAnnaallyyssiiss 55..66 DDrriifftt OOffff aanndd WWeeaakk PPooiinntt AAnnaallyyssiiss 55..77 RRiisseerr RReeccooiill AAnnaallyyssiiss 55..88 High Current Environment 5.9 Hang-off Analysis

SECTION 6: RISER OPERATIONS

66..11 IInnttrroodduuccttiioonn 66..22 RRiisseerr OOppeerraattiinngg MMaannuuaall 66..33 RRiisseerr OOppeerraattiioonnss IInnffoorrmmaattiioonn SSyysstteemmss 66..44 PPrreeppaarriinngg ttoo RRuunn RRiisseerr 66..55 RRiisseerr RRuunnnniinngg aanndd RReettrriieevvaall 66..66 IInnssttaalllleedd RRiisseerrss OOppeerraattiioonnss 66..77 CCoonndduuccttoorr aanndd CCaassiinngg IInnssttaallllaattiioonn 66..88 TTrrooppiiccaall DDiissttuurrbbaannccee EEvvaaccuuaattiioonn 66..99 EEmmeerrggeennccyy DDiissccoonnnneecctt 66..1100 MMoooorreedd VVeesssseell CCoonnssiiddeerraattiioonnss 66..1111 CCoommpplleettiioonn aanndd WWeellll TTeessttiinngg

SECTION 7: RISER INTEGRITY

77..11 BBaassiiss ooff IInnssppeeccttiioonn RReeqquuiirreemmeennttss 77..22 MMaaiinntteennaannccee aafftteerr RRiisseerr RReettrriieevvaall 77..33 OOtthheerr RRiisseerr SSyysstteemm MMaaiinntteennaannccee 77..44 TTrraannssppoorrttaattiioonn,, HHaannddlliinngg aanndd SSttoorraaggee 7.5 Scheduled Field Inspection & Maintenance 7.6 In-Service Inspection 7.7 Guidance on Components to be Inspected 7.8 Inspection Objectives and Acceptance Criteria 7.9 Operational Records for Riser Components

SECTION 8: SPECIAL SITUATIONS

ANNEXES

A Riser Analysis Data Worksheet

B Associated Topics

C Sample Riser Calculations

D Example Riser Running Procedure

E Sample Calculation of Max. and Min. TJ Stroke

F Bibliography

Figure 3 Table of Contents of Revised API RP16Q / ISO

13624[Draft]

SECTION 1: SCOPE

SECTION 2: REFERENCED DOCUMENTS

SECTION 3: DEFINITIONS AND ACRONYMS

SECTION 4: COUPLED DRILLING RISER/ CONDUCTOR ANALYSIS METHODOLOGY AND WORKED EXAMPLES

44..11 CCoouupplleedd MMeetthhooddoollooggyy 44..22 DDeeccoouupplleedd MMeetthhooddoollooggyy 44..33 AAnnaallyyssiiss CCoonnssiiddeerraattiioonnss 44..44 MMooddeell DDeevveellooppmmeenntt 44..55 CCoouupplleedd RRiisseerr AAnnaallyyssiiss 44..66 DDeeccoouupplleedd RRiisseerr AAnnaallyyssiiss 44..77 WWoorrkkeedd EExxaammppllee

SECTION 5: CONDUCTOR CASING SOIL-STRUCTURE MODELING METHODOLOGY

55..11 OOvveerrvviieeww 55..22 PPrroocceedduurree ffoorr PPrreeddiiccttiinngg SSooiill BBeehhaavviioorr 55..33 MMooddeelllliinngg ooff SSooiill--SSttrruuccttuurree IInntteerraaccttiioonn

SECTION 6: DRIFT-Off ANALYSIS METHODOLOGY AND WORKED EXAMPLE

66..11 DDrriifftt--ooffff AAnnaallyyssiiss MMeetthhooddoollooggyy 6.2 Worked Example

SECTION 7: WEAK POINT ANALYSIS METHODOLOGY AND WORKED EXAMPLE

77..11 WWeeaakk PPooiinntt AAnnaallyyssiiss MMeetthhooddoollooggyy 7.2 Worked Example

SECTION 8: RECOIL ANALYSIS METHODOLOGY AND WORKED EXAMPLE

88..11 IInnttrroodduuccttiioonn 88..22 RReeqquuiirreedd IInnffoorrmmaattiioonn 88..33 PPeerrffoorrmmaannccee CCrriitteerriiaa 88..44 WWoorrkkeedd EExxaammppllee

Figure 4 Table of Contents of API Technical Report (API 16TR1)

for Revised API RP 16Q / ISO 13624[Draft]


Figure 5 Typical Riser System Coupled Model

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

4.5

5.0

0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5 5.0 5.5 6.0 6.5 7.0 7.5 8.0 8.5 9.0

Vessel Offset (% Water Depth)

Rot

atio

n of

Low

er F

lex

Join

t (d

egre

es)

Coupled Model

Decoupled Model

Figure 6 Coupled vs. Decoupled Modeling

Undeformed Conductor Casing

Mudline y, Deflection

Deformed Conductor Casing

p, Soil Resistance

M

F

x, Longitudinal axis

θ,Rotation

Figure 7 Soil Loading on Casing

Ves

sel E

xcur

sion

(%W

D)

0

2

4

6

8

10

12

14

0 20 40 60 80 100 120 140 160 180 200

EDS Disconnect

TLAG+TDYN

TDISC

Alarm 1Alarm 1 Alarm 2Alarm 2

Ves

sel E

xcur

sion

(%W

D)

0

2

4

6

8

10

12

14

0 20 40 60 80 100 120 140 160 180 200

EDS Disconnect

TLAG+TDYN

TDISC

Alarm 1Alarm 1 Alarm 2Alarm 2

Figure 8 Drift-Off System Limits

Spring Elements to Model Soil-Structure Interaction

Mudline

Conductor Casing

BOP

Bare Riser Joints

LMRPLower Flex Joint

Riser Buoyancy Joints

Drill Deck (RKB)

Upper Flex Joint

Tensioners

Telescopic Joint

MWL

Lower Flexjoint(Articulation Element)

Fixed in All Degreesof Freedom

Tensioner System Modelledwith Spring/Beam Elementsor Equivalent Vertical Tension

Upper Flexjoint(Articulation Element)

Heave/Surge/Sway

Heave/Surge/Sway

Surge/Sway/Pitch/Roll

Time (seconds

Ves

sel E

xcur

sion

(%W

D)


Drilling RiserConfiguration

Evaluation CriteriaDetermine Limiting Load or Motion Disconnect Criteria

for Critical Components of the System(e.g. riser joints, flex-joints, connectors etc.)

Perform Drift-off Analysis• Initial Static Analysis with current loads, followed by• Time Domain Vessel Drift-Off Analysis and then• Time Domain Dynamic Regular Wave Analyses

Evaluate Results1. Evaluate limiting Loads/Stresses at Critical Points and2. Identify Disconnect Offsets for all Critical Points in the

Riser System and the criteria forcing disconnect.

Drift-Off Analysis Complete

Results1. Determine disconnect initiation point from the critical

disconnect offsets,2. Adjust for the time lag between initiation and

disconnect, using the vessel drift-off/drive-offexcursion time history

Figure 9 Drift-Off Analysis Flow Chart


Determine Failure Load Capacities of Potential Weak Points of the System e.g. riser joints, connectors etc.

Perform Static Current, Quasi-Static/Dynamic Offset, and Dynamic Regular Wave Analyses

Compare Loads at Potential Weak Points from Analysis with Failure Loads to Determine Weak Point of the System

Is the Weak Point at a Suitable Location?

Weak Point AnalysisComplete

Redesign Ancillary Equipment or Riser Configuration

Yes

no


Determine Failure Load Capacities of Potential Weak Points of the System e.g. riser joints, connectors etc.

Perform Static Current, Quasi-Static/Dynamic Offset, and Dynamic Regular Wave Analyses

Compare Loads at Potential Weak Points from Analysis with Failure Loads to Determine Weak Point of the System

Is the Weak Point at a Suitable Location?

Weak Point AnalysisComplete

Redesign Ancillary Equipment or Riser Configuration

Yes

no

Figure 10 Weak Point Analysis Flow Chart

0

5

10

15

20

25

30

35

40

0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5 5.0 5.5 6.0 6.5 7.0 7.5 8.0 8.5 9.0 9.5 10.0 10.5

Offset (% Water Depth)

Str

oke

Leng

th f

rom

Mea

n (f

t)

-3.0

-2.0

-1.0

0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

8.0

9.0

10.0

11.0

12.0

13.0

Ro

tati

on

of

Up

per

Fle

xjo

int

(deg

rees

)

Stroke-OutStroke LengthDisconnect Limit Slip JointUFJDisconnect Limit Flex JointsLFJIFJ

flex joint disconnect limit

slip joint stroke-out

disconnect limit slip joint

UFJ rotation

slip joint stroke lengthfrom mean

IFJ rotation

LFJ rotation

Figure 11 Weak Point Graphical Results

0

200

400

600

800

1000

1200

1400

1600

1800

0 5 10 15 20 25 30 35 40 45

Vessel Offset (% of Water Depth)

Ben

din

g M

om

ent (

kip

.ft)

Component 1 FailureComponent 1 LoadComponent 2 FailureComponent 2 LoadComponent 3 FailureComponent 3 Load

Weak PointWeak Point

0

200

400

600

800

1000

1200

1400

1600

1800

0 5 10 15 20 25 30 35 40 45

Vessel Offset (% of Water Depth)

Ben

din

g M

om

ent (

kip

.ft)

Component 1 FailureComponent 1 LoadComponent 2 FailureComponent 2 LoadComponent 3 FailureComponent 3 Load

Weak PointWeak Point

Figure 12 Determination of Weak Point