Copyright 2003, Offshore Technology Conference This paper was prepared for presentation at the 2003 Offshore Technology Conference held in Houston, Texas, U.S.A., 5–8 May 2003. This paper was selected for presentation by an 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 Exploration wells are currently being drilled in water depths up to 10,000 feet. Completion of these ultra deepwater wells creates demand for innovative well system and intervention technology. Equipment design should not limit rig selection during initial installation or subsequent intervention activities. Selection of optimized intervention packages that function on both moored and dynamically positioned (DP) vessels will provide access to a wider rig market and create the opportunity to make substantial life cycle cost savings. This paper discusses unique design and operational requirements for the well system and intervention equipment to allow safe deployment and operation from DP vessels. Introduction Although mooring technology has made tremendous gains in recent years, DP operations still provide advantages for installation and intervention activities on fragmented, deepwater field developments. However, the decision to use dynamically positioned vessels presents far-reaching implications for both equipment specification and operating philosophy. Key operational considerations such as mitigation of DP station keeping incidents, watch circle management, ESD philosophy and vessel interfaces are presented to illustrate the challenges faced to successfully integrate the intervention system to the DP vessel. The design requirements imposed upon the well system and intervention equipment by DP operations are also discussed at some length. Functional requirements for Wellhead equipment, Xmas Trees, open water Completion / Workover (C/WO) risers, Horizontal Tree (HXT) intervention strings and drill pipe installation systems are presented. The paper concludes that the limitations of the intervention system must be fully understood with respect to the DP vessel response and that considerable planning and engineering assement is required to ensure safe installation and intervention operations.

Operational Considerations The discussion that follows presents some of the key operational constraints and vessel interfaces, which dictate the requirements for well systems and intervention equipment that are deployed from DP vessels.

DP Station Keeping Incidents. One of the key risks that must be quantified to allow proper specification of equipment and development of operating procedures is the likelihood and associated consequence of DP station keeping incidents. The frequency of a station keeping incident is dependent upon the reliability of the DP system and the exposure time during which the vessel is connected to the well. Various tooling packages will be used throughout the completion or intervention process, each with a different exposure time and associated level of risk depending upon the type of operation being completed. Therefore, it is inappropriate to assume that generalized recommendations will cover all tooling packages and operating procedures.

The performance and reliability of DP systems typically used on semi-submersible and monohull drilling rigs has improved to an extent that a station keeping incident requiring disconnect of the marine riser should be no more frequent than once every ten years1. This data can be used to predict the frequency of DP station keeping incidents that could be encountered during well completion or intervention activities. Figure 1, shows estimated incident frequencies based on exposure time (number of days connected to the well) and level of activity (well completions or interventions per annum). This graph demonstrates that the risk of encountering a station keeping incident increases rapidly with exposure time and level of activity. Table 2 nominal exposure times, which were referenced against Figure 1 to estimate the relative risk associated with each step of the completion or intervention procedure. This provides a method to identify areas where further investment is justified to reduce DP related risks to an acceptable level.

Interestingly, operator error is the predominant reason for DP station keeping incidents1. Operator training and implementing periods of heightened awareness during completion operations could therefore make a considerable contribution to improve overall DP safety.

Watch Circle Management. DP vessels operate a transitioned watch circle system based on stop light colors. The normal operating region is designated as the green zone. The vessel travels through the yellow zone and enters the red

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Design of Well Completion and Intervention Systems For Deployment From Dynamically Positioned Vessels David Harrold FMC Technologies Inc. and Brian J. Saucier DeepMar Consulting Services

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zone as it reaches an unacceptable offset based on the allowable stress limit of the intervention riser or marine riser. The red zone limit must be established to provide sufficient time for decision making and to allow emergency shut down (ESD) and safe disconnect from the well. The time permitted in the yellow and red zones is dependant on how quickly the rig moves off location compared to the time required for the intervention system to complete ESD. The goal is to increase the vessel offset that can be tolerated in the green and yellow zones so that the intervention system does not have an overly restrictive operating envelope. It is therefore critical to properly understand the limitations of the intervention system and how they relate to the vessel response upon loss of station keeping (i.e. rate of drift off or drive off). A detailed evaluation process must be completed each time the intervention system is “married” to a new vessel. Comprehensive structural and hydraulic analysis studies should be completed for the intervention system to determine the riser allowable stress limits and ESD time, respectively. The results of these studies should be compared against the vessel’s operational and environmental responses to establish a watch circle management plan. Considerable modification to an existing intervention system may be required to make it compatible with the selected vessel and to avoid an overly restrictive watch circle. It should also be noted that the type of intervention operation that is being undertaken (i.e. flowing well, coiled tubing or wireline operations), will also impact the watch circle limits and the resulting riser management. For example, coiled tubing mode will require tighter offset limits for the green and yellow safe operational zones than would be required in flowing mode. ESD in coiled tubing mode will take longer than in flowing mode as more ram / valve closures are required to shear the coiled tubing and secure the well.

ESD Philosophy. Emergency shutdown procedures are critical to the safe operation of any workover intervention package. A staged shut down sequence is generally recommended, as this will allow a measured response to be implemented during an escalating DP incident. Three shut down levels are recommended. ESD level 1 (ESD1) normally provides surface isolation of the well by closing a flowhead wing valve. ESD level 2 (ESD 2) additionally isolates the well subsea at the intervention package. ESD level 3 (ESD3) instructs disconnect of the intervention system from an isolated well. Depending upon the complexity of the intervention system and its controls (IWOCS), different modes of operation can also be applied within each of these ESD levels to properly address wireline, coiled tubing and flowing modes. This is particularly useful to avoid unnecessary cutting of wireline or coiled tubing, which could result in considerable down time to allow recovery. When making this decision, a balance between complexity and functionality must be reached to provide an operable system.

A philosophy must be established to relate each of the ESD levels (ESD1, ESD2 and ESD3) to the green, yellow and red watch circle zones discussed above. Typically, ESD1 will be used in the green zone to isolate a flowing well from the vessel. As the vessel moves to the extremities of the yellow zone, ESD 2 will be implemented. If vessel position is not

restored and it enters the red zone, then ESD 3 will be initiated.

A double barrier philosophy should be adopted on all intervention systems following ESD3. At least two sealing barriers that are capable of cutting heaviest coiled tubing or logging cable etc. that will be encountered should remain subsea after disconnect.

Interface to Rig and Tensioner Equipment. Some interesting issues exist when tensioning an open water C/WO riser from a monohull DP vessel. The vessel must have the freedom to rotate around the intervention riser as it weather vanes. Therefore, a rotational degree of freedom must exist between the riser and the vessel. The same is true between the flowhead and riser or landing string for both Horizontal Tree (HXT) and Conventional Tree (CXT) intervention systems.

Higher rig offsets can be experienced in DP operations, so greater clearance is required between the flowhead and the drill floor to prevent clashing. Long intermediate riser joints are used between the flowhead and tension joint to provide this spaceout when using an open water C/WO riser (See Figure 2). These long intermediate joints can present considerable handling issues on the rig. They will also no longer permit “free standing” of the flowhead. Tension must therefore be applied to the flowhead from the crown mounted compensators (CMC) to keep these long intermediate joints stable and to prevent their collapse. This presents a tension management issue. Tension is applied simultaneously at two points (at the CMC and rig tensioners), therefore the stroke of the CMC and the rig tensioners needs to be aligned to ensure the rig tensioners bottom out first in the event of extreme offset conditions. Effectively, the offset of the vessel will be restricted by the stroke of the CMC if it is less than that of the rig tensioners.

Deepwater drilling rigs are equipped with high capacity tensioners to tension the marine riser. The tension applied to an open water C/WO riser is much lower than that required for the marine riser. At lower tensions the rig tensioners work less efficiently and so large variations in effective tension can be encountered. Tension variation can be significant and needs to be considered when designing the open water C/WO riser. Tension management can be improved if an instrumented riser joint is used which can provide real time feedback of riser effective tension.

On some DP rigs power is diverted to the thrusters during extreme offsets to bring the rig back on location. Loss of power to the CMC will cause it either to lock out or to release tension depending on its design. This event has implications for both CXT and HXT intervention systems and must be addressed by their designs.

Some DP intervention vessels and MSV’s provide only top tension from the CMC. Special consideration needs to be given to the joints at the top of an open water C/WO riser as they will not typically be designed to withstand the high loads that they will experience in this mode of operation. A considerably tighter operating envelope will be encountered with such a vessel.

Interface to Vessel Safety Systems. Tie in of the IWOCS to the rig safety systems must also be addressed. The degree of automation adopted between these systems requires careful consideration. Flow test and hydrocarbon processing facilities

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must interface directly to the IWOCS so that they can automatically initiate ESD1 in event of a serious process upset. However, there is no requirement for the flow test facilities to access the other levels of the ESD sequence (i.e. ESD2 and ESD3). The rig fire and gas system should provide an alarm at the IWOCS control station as opposed to an automatic shut down command. This will allow some time for evaluation before taking action and will prevent minor incidents from triggering an ESD, which could be a hazardous event itself. ESD2 and ESD3 commands should be limited to the IWOCS control station and its remote ESD panels, which should be situated on the drill floor, and bridge areas of the vessel. ESD3 should be coordinated through the driller as opposed to being automatically triggered by the rig DP system. In the case of the open water intervention riser, ESD3 should provide an automatic activation signal to the recoil system on the rig tensioners to react the sudden loss of tension and decelerate the riser safely upon disconnect. The HXT landing string needs to be disconnected prior to BOP disconnect in the event of drive off. This should be done in a manual manner where the driller coordinates operation of both control systems as opposed to using a control system link. This is preferable to integrating a common BOP / landing string control system due to the complexity involved. In making this recommendation, it should be remembered that the BOP stack shear rams could cut the landing string shear joint in the event that operational practices breakdown.

Management of Umbilicals. Vessel offset needs to be considered when using umbilicals. A lazy-S configuration must be used to provide variable length to accommodate offset displacements as the vessel moves off location. Additionally, constant tension umbilical reels should also be used to provide further manageability in drift off / drive off conditions. Equipment Requirements Each component of the well system and its associated installation / intervention tooling needs to be examined to determine if it is fit for its purpose. The discussion that follows proposes requirements for the components of the well system and their related installation / intervention tools. The requirements discussed are limited to those imposed by DP operations. In practice, there will be other key equipment requirements, which are dependent upon specific applications that are unrelated to DP operations. These additional requirements are beyond the scope of this paper.

Wellhead System. The key drivers related to the wellhead system are specification of the structural conductor and selection of the hub profile on the high-pressure housing (See Figure 3). The loads transmitted to the wellhead from the drilling rig’s marine riser during drilling and completion operations define these requirements. A conservative approach should be adopted where a system weak point is established above the well control equipment (i.e. failure of the marine riser), such that any resulting failure due to uncontrolled drive off will not result in a blowout or loss of well control. This philosophy leads some operators to select heavy wall 38” conductor strings and DWHC® double clamp hub or super duty H4® mandrel profiles for their high-pressure wellhead housings. However, there is also a belief within the industry that standard deepwater wellheads with single clamp

hub or standard H4® mandrel profiles are sufficient to react the loads that will be encountered. In all cases a rigid lock system should be employed between the high pressure and conductor housings to permit better fatigue control and transmission of loads.

Wellhead selection should be made so that it does not limit the choice of available vessels to complete intervention and workover activities in later field life. Also the impact of wellhead selection on the resulting Xmas Tree design should be fully understood (see discussion on Xmas Tree System).

Conductor and high-pressure wellhead housings are installed from moored drilling vessels in open water on drill pipe using simple cam actuated running tools that do not permit quick disconnect. These tools are used for very short duration activities and so exposure to drive off / drift off is very unlikely (see Table 1). The incident frequency associated with these tools is less than one major position keeping incident every 300 years if 10 wells are drilled annually. Therefore, using these same running tools when installing from a DP vessel presents little increase in operating risk. Casing hangers are installed through the marine riser on drill pipe, which can be sheared by the BOP rams in the event of drive off, so their running tools do not require any modification when deployed from a DP rig either.

Xmas Tree System. The impact of DP operations on the Xmas Tree will differ depending upon the type of system employed. A HXT is potentially more affected by DP operations than a CXT because its installation procedure dictates that marine riser loads are transmitted through the HXT (see Figure 4). The HXT re-entry profile, spool body and wellhead connector must all be rated to transfer the marine riser loads to the wellhead system below (see Figure 5). If a DWHC® double clamp hub or super duty H4® mandrel type wellhead system is employed, this can have a dramatic impact upon the size and weight of the HXT (more than a 50% weight increase could be experienced), since the HXT must employ this wellhead profile on its re-entry hub and must provide a suitable connector to interface this type of wellhead. The structures and frames, which package the HXT are also impacted, since they must grow to accommodate the increased size of the spool body and wellhead connector. Increase in the HXT size and weight can present considerable handling issues on the rig, which should not be underestimated. Integrated selection of the wellhead and HXT will produce the most satisfactory result, as this will allow decisions to be made considering the system as a whole.

The CXT has no direct interface to the drilling rig’s BOP stack or marine riser. However, the CXT is normally installed using a C/WO riser (see Figure 6) and could be exposed to higher environmental loads due to the greater rig offsets that could be experienced when completing with a DP rig. Typically, a deep-water CXT installed from a moored drilling rig has a 13 5/8” re-entry hub. This re-entry hub profile needs to grow to a 16 ¾” or 18 ¾” (see Figure 7) to accommodate the potentially higher C/WO riser loads that could be experienced during installation from a DP rig. This is a relatively minor modification compared to those discussed above for the HXT. The C/WO riser loads imparted to the CXT allow it to utilize a standard 18 ¾” 15K wellhead connector, although connector selection is also dependent

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upon the wellhead profile. A super duty H4® mandrel dictates that a larger wellhead connector is used irrespective of loads transmitted to the CXT by the C/WO riser. Other common wellhead types, including DWHC® double clamp hub wellheads will permit the CXT to use a standard 18 ¾” 15K wellhead connector (i.e. only the upper clamp hub is used).

Some CXT’s complete on Tubing Head spools (see Figure 7). Marine riser loads are transmitted through these Tubing Head spools when the well is completed, and so they are subject to the same modifications described for the HXT above. However, a tubing head spool is a much simpler piece of equipment than an HXT and so the impact on its size and weight is less significant (approximately a 20% weight increase). In other respects CXT’s and HXT’s are unchanged from the configuration that would normally be installed from a moored vessel.

Completion / Workover Riser System. CXT’s and HXT’s use quite different C/WO riser systems. The CXT uses an open water C/WO riser, which comprises a flowhead, riser pipe, an emergency disconnect package (EDP), a lower riser package (LRP) and an associated IWOCS (see Figure 6). The HXT uses an internal landing string that is installed within the marine riser and comprises a flowhead, premium tubing landing string, a Retainer Valve (RV), a shear joint, an Emergency Disconnect Connector (EDC), a Subsea Test Tree (SSTT) and an IWOCS system (see Figure 8). CXT and HXT intervention systems share some common challenges, but also have some unique challenges associated with operating in a DP environment, which are summarized, below.

Open Water Riser Systems. Open water C/WO risers have a high criticality rating due to the long exposure operations they are used to complete and because of the high consequences of their failure (see Table 1). Therefore, these equipment packages merit further examination to ensure the operational risks they present are acceptable and manageable.

A rigorous structural analysis needs to be completed to determine the stresses in riser tubulars. In addition to a standard riser analysis, a non-linear weak point analysis should also be completed to determine the behavior and failure point in the riser at extreme vessel offsets. Both the design and manufacture of riser joints are impacted to accommodate the high tensions that could be encountered. Tubular wall thickness, material strength and riser connector capacity all need to increase. Some of the verification techniques typically used for TLP risers and SCR’s, such as crack tip opening displacement (CTOD) testing, should be considered to combat against failure at the high tensile loads that could be encountered.

DP operations require that a greater clearance be maintained between the flowhead and drill floor. This means the length of the intermediate joint between the flowhead and tension joint will have to increase to satisfy this spaceout. Due to manufacturing constraints and handling limitations on the rig, it is likely that the intermediate joint will have to be split into two pieces. Additionally, the intermediate joints need to be tensioned by the CMC through the flowhead, as they are too long to remain “free standing”. These joints require contingency protection in case CMC tension is lost. One method of addressing this is to tie the flowhead into the top drive rails which will provide enough stability to allow

free standing of the intermediate joints for short periods of time until CMC tension is restored. This obviously has an impact on the flowhead design. A considerable engineering assessment is required to ensure that neither the intermediate joints or flowhead become overstressed as a result of this new boundary condition.

The connections in the EDP and LRP need to be examined to ensure they have sufficient structural capacity. In moored operations the connection between the LRP and the Tree is typically a 13 5/8” hydraulic connector. This connection will need to be increased to allow a greater safety margin and to provide a less restrictive operating envelope. DP operations will require that the LRP connector is increased to a 16 ¾” or 18 ¾” connector.

HXT Intervention Systems. HXT landing strings are classed as high criticality equipment for the same reasons explained above for open water C/WO riser (see Table 1).

HXT landing strings also face some interesting issues to interface with tension systems. The HXT landing string is normally contained within the marine riser and is suspended and tensioned from the CMC. On some DP rigs power is diverted to the thrusters during extreme offsets to bring the rig back on location. When power is lost from the CMC, it can lock out and cease to provide compensation. As the vessel heaves this will produce unacceptably high stresses in the HXT landing string. Therefore, a contingency source of compensation must be provided between the flowhead and CMC. This problem has been addressed on some projects by using a compensated tension frame between the flowhead and CMC.

Special consideration needs to be given to HXT landing string tubulars, since they could be subjected to higher BOP flex joint and marine riser ball joint angles. Clearance within the marine riser and flexibility of the landing string tubulars should be maximized to make the operating envelope less restrictive.

In completion mode the HXT uses two control umbilicals. An umbilical is used inside the marine riser to control the SSTT. A second external umbilical is used outside of the marine riser, to control the HXT. Flying leads are used to make the connections between the LMRP and HXT (see Figure 4). Quick disconnect systems are often used at this interface in moored operations to prevent damage to the umbilical or HXT stab plate in the event of an LMRP disconnect. In DP operations this requirement becomes mandatory and should not be questioned. Disconnect is best addressed by incorporating a simple mechanical guillotine into the flying lead, which provides a controlled break point. The flying lead is then replaced to allow commencement of operations. Design of complex quick disconnect stab plates between the LMRP and BOP should be avoided, as it is extremely time consuming to integrate them to the BOP stack and verify their performance.

IWOCS Systems. DP vessels can rapidly move off location if drive off occurs. Excursion to extreme rig offsets that could result in structural damage can occur in less than 1 minute during drive off. Therefore, both HXT and CXT intervention systems must provide much faster emergency shut down (ESD) sequences than are normally used in moored operations. Typically, open water C/WO risers and HXT

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landing strings must provide disconnect times of 40 and 20 seconds or less, respectively2. The HXT landing string must provide a faster disconnect time than the open water C/WO riser since it must complete its ESD sequence and provide a safe margin prior to BOP stack disconnect. Highly reliable Electro-Hydraulic (E/H) control systems become a mandatory requirement. Additionally, substantially increased remote accumulation is required, which can result in considerable weight and space increases.

Incorporating an Electro-Hydraulic Multiplexed (EH/MUX) control system into an open water C/WO riser is relatively straight forward, as the same field-proven, established technology used on Xmas Tree’s can be applied. The EH/MUX control system for the HXT landing string must be packaged so that it is compact enough to drift the marine riser (typically, 19 ½” inner diameter) and is also located in close proximity to the landing string tubulars. The landing string EH/MUX control system can therefore be exposed to high temperatures and vibrations during well testing, which can affect its reliability. Reliability concerns have resulted in some manufacturers sponsoring the use of simplex E/H systems in DP applications, although E/H MUX systems are feasible and provide the advantage of reduced umbilical size and facilitate data collection2. Reduction in umbilical size is useful as this will increase clearance in the marine riser and will therefore improve the operating envelope of the HXT landing string.

Redundancy within the IWOCS system must be reviewed and re-evaluated due to the increased risk of disconnect in DP operations. Redundancy methods differ for HXT and CXT IWOCS. The HXT landing string normally incorporates a secondary hydraulic circuit that is functioned by applying annular pressure via the BOP stack choke / kill lines2. This activates an ESD sequence, which causes the RV and SSTT ball valves to close and its EDC to disconnect. This type of shut down sequence can be used to retrieve the SSTT control system in event of failure during normal operation, but does not provide a fast enough response to isolate the well and disconnect during drive off. The HXT intervention system addresses this issue by providing a shearable joint above the SSTT, which is spaced out to align with the BOP shear rams. This joint can be cut by the BOP shear rams to effect a quick disconnect, which also shears and vents control lines allowing the SSTT ball valves to close (SSTT ball valves are fail safe close). Spaceout of the HXT intervention system in the BOP stack is therefore important. This can lead to considerable re-configuration to allow the intervention system to be used with multiple rigs and can present spaceout challenges with some BOP stack arrangements.

The CXT intervention system is decoupled from the rig’s BOP stack. Therefore, the redundant control system must be wholly contained within the CXT C/WO riser system. The redundant control system needs to be independent of the primary EH/MUX control system and the IWOCS umbilical. An independent acoustic control system, similar to that used on BOP stacks and often referred to as a deadman system is recommended. This system will allow remote accumulation on the C/WO riser system to be activated to function the LRP rams and EDP connector to isolate the well and safely

disconnect in event of the IWOCS umbilical or the EH/MUX system becoming inoperable.

Tubing Hanger Installation Systems. The HXT tubing hanger (TH) is installed by the internal landing string described in the Completion / Workover Riser section above, so discussion in this section is limited to CXT TH installation systems.

When installing from a moored rig, the TH installation system comprises a landing string (typically premium tubing or specialty drill pipe), a BOP spanner joint (BOPSJ), a tubing hanger running tool (THRT) and an IWOCS system (see Figure 8). The BOPSJ is a heavy wall cased joint, which spans the BOP rams and annulars and cannot be sheared by the BOP. The IWOCS system is a direct hydraulic control system, which will not provide a fast response time in deepwater. Therefore, the CXT TH installation system used from a moored rig is not configured to provide a quick disconnect feature. The CXT TH installation system is connected to the well for short periods of time and is considered a medium criticality tool (see Table 1), so the requirement to add a quick disconnect feature could be questioned. However, a shear joint can be added to the BOPSJ without incurring much cost, so this seems a wise investment considering the protection it will provide. In addition to the shear joint, an emergency disconnect connector (EDC) similar to that used on an SSTT could also be added to the BOPSJ to provide a hydraulic disconnect. This would also impose design changes upon the IWOCS system to improve its response time. The impact on the control system is not as dramatic as it may first appear. Only one function in the system (EDC unlock) requires a fast response time, so a simplex E/H control system incorporating subsea accumulation is sufficient as opposed to a full EH/MUX control system. The choice to incorporate an EDC is mostly an economic decision. Incorporating an EDC into the BOPSJ will permit a much quicker re-connect to the completion, so much less nonproductive down time will be incurred compared to recovery from shearing the BOPSJ. If the BOPSJ is sheared, time consuming fishing and milling operations will be required to retrieve the lower part of the BOPSJ and the THRT. Washout trips will also be required to remove any milling or shear debris from the BOP stack prior to re-connection to the completion. The incident frequency associated with the TH installation tools is less than one major position keeping incident every 300 years if 10 wells are completed annually, so incorporation of the shear joint alone should be adequate.

Some CXT THRT’s use wireline installed darts to activate THRT secondary release systems. These systems are inoperable in a DP environment since they cannot be accessed post shear. A secondary release circuit similar to that used on SSTT’s and operated by BOP annular pressure must be used.

Xmas Tree Drill Pipe Installation Systems. XT’s are often installed on drill string. In moored operations, the drill string is connected to the XT using either a simple cam actuated running tool or a hydraulically operated connector. Often the hydraulic connector is operated by an ROV or by a direct hydraulic control system. Such installation systems do not permit fast disconnect, nor do they provide a high angle release capability. Requirements for the drill pipe installation

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system are dependent upon the duration the drill pipe remains connected to the XT. In some batch setting operations, this will be a very short duration, where the XT is installed to the well and minimal pressure tests are conducted prior to disconnecting running tools. In such cases, due to the short duration that the drill pipe is connected to the XT, the running tools used in moored rig operations are acceptable. However, in other installation scenarios extensive function and pressure testing will be completed while connected to the XT. This increases the exposure time, so quick disconnect running tools with high angle release capability should be used to permit safe disconnect to prevent structural damage upon drive off. The most practical solution is to provide a high angle release hydraulic connector, which locks to an external profile on the XT re-entry hub. A simplex E/H control system with subsea accumulation is also required to provide the hydraulic power to quickly unlock the running tool connector.

System Weak Point Locations. A weak point analysis should be completed for all intervention systems deployed from DP vessels. The intervention system should be designed so that the weak point is located above the primary well control barriers. In the case of the CXT intervention system, the weak point should be located in the riser pipe above the EDP and LRP. Similarly, the weak point in the HXT intervention system should be located above the SSTT. This will ensure the system is inherently safe upon failure to disconnect, since well bore barriers will automatically fail to the closed position when the riser tubulars and umbilical fail at the weak point above. The system weak point should be positioned by increasing the capacity of the connections between the well control equipment and well as opposed to designing an intentional “weak link” into the riser or landing string tubulars. In practice, it is difficult to design reliable “weak link” systems as they tend to rely on tight control of material properties. Therefore, it is better to design the well control equipment with large safety factors to ensure the weak point is located in the riser tubulars.

Assessment of Equipment Reliability. Estimating the reliability of subsea equipment in a rigorous, quantitative manner is currently difficult due to the lack of available reliability data. However, a good qualitative assessment can be made. Reliability methods such as fault tree analysis should be used to identify critical components and determine the level of redundancy that exists within the intervention system. This will allow single point failures to be eliminated from the system. FMECA studies should also be completed to analyze all new equipment and its associated installation methods. The benefits gained by increasing system complexity should be scrutinized against their effect on overall system reliability. The designer and end user should strive to employ the best available technology and should maximize the use of field proven equipment for critical system components.

Equipment Qualification Requirements. At the outset of the project a comprehensive design basis should be created detailing service conditions and operational requirements for the equipment. A rigorous review should be carried out to determine the qualification status of all existing and new equipment to determine what additional qualification testing is required. As a minimum, equipment qualification should

address fitness for purpose with respect to pressure and temperature rating, water depth, environmental loads and hydrocarbon / chemical exposure. Additionally, shear tests should be completed to qualify LRP or SSTT shear mechanisms to ensure they can cut the heaviest coiled tubing, wireline and logging cable, etc., they will be exposed to during service. A good baseline should be to ensure that all seals, valve bore seal mechanisms, shear mechanisms and connectors meet the qualification requirements of API 6A, PR2, Appendix F and API 17D / 17G. Open water C/WO riser joint connectors should be qualified accordance with ISO 13628-7, Appendix I. It is also recommended that a sample riser joint undergoe a tensile test to failure to verify its ultimate capacity. Cut tests should be carried out on the shear joint for the HXT and CXT intervention systems using representative BOP shear rams. A comprehensive FAT and SIT test program should be carried out to complete final verification of equipment performance.

Maintenance Philosophy. A real commitment must be made by the end user to implement a thorough maintenance plan for any intervention system. This becomes increasingly important in a DP environment where the reliability of the equipment is paramount. Extended successful operations must allow for adequate time to maintain and refurbish the system’s critical components. Continuous rig site and shore base maintenance programs are required to reduce downtime and mitigate risk. Recognition of any single point failure modes in the control system are key to providing a discrete focus on these components both onshore and offshore. Tracking performance of key components and recognizing signals that failure or improper operation is occurring is a key performance indicator that should be followed. As a minimum the maintenance plan should achieve the following: 1) Track usage and performance of critical components; 2) Ensure fluid cleanliness throughout hydraulic systems; 3) Ensure regular replacement of hydraulic filters; 4) Maintain and verify the performance of valve bore sealing and cutting/shearing mechanisms; 5) Maintain and verify the performance of IWOCS and disconnect systems; 6) Ensure routine and proactive replacement of consumable components; 7) Feedback field history to optimize maintenance intervals to further reduce risk of equipment malfunction. Conclusion Equipment and procedures used in moored operations are not directly transferable to DP vessels. Far-reaching equipment and procedural modifications are required to reduce operating risks on DP vessels’s to an acceptable level. Selection of a DP vessel must be made at the outset of the installation or intervention campaign to allow proper planning and engineering assessments to be completed to ensure successful integration of the intervention system to the vessel. The limitations of the intervention system and the response of the DP vessel with respect to drive off / drift off must be fully understood to allow safe operating procedures to be established. Intervention systems deployed from DP vessels require much faster ESD and disconnect times than their moored rig equivalents to provide protection in event of drive off. Redundancy level and reliability of IWOCS systems is a key concern. Addition of back control systems such as an

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acoustic deadman should be considered to improve the redundancy level of IWOCS systems used on open water risers. DP intervention systems should be designed so that the weak point is located above the primary well control barriers. This will ensure the system is inherently safe upon failure to disconnect, since well bore barriers will automatically fail to the closed position when the riser tubulars and umbilical fail at the weak point above. A qualitative reliability assessment should be made to determine the critical system components and to eliminate single point failures where practical. The intervention system and its components should be fully evaluated to ensure that it is qualified for the service conditions to which it will be exposed. A comprehensive maintenance plan must be implemented to ensure that the system reliability is verified and maintained throughout the life of the intervention system. Acknowledgements The authors would like to thank the management of FMC Kongsberg Subsea for giving permission to publish this paper. Thanks are also extended to the technical illustrations department within FMC Konsberg Subsea who provided the figures referenced throughout this paper. Nomenclature API = American Petroleum Institute BOP = Blowout Preventor BOPSJ = BOP Spanner Joint CMC = Crown Mounted Compensator CTOD = Crack Tip Opening Displacement CXT = Conventional Vertical Xmas Tree C/WO = Completion / Workover DP = Dynamically Positioned EDC = Emergency Disconnect Connector EDP = Emergency Disconnect Package E/H = Electro-Hydraulic EH/MUX = Electro-Hydraulic Multiplexed ESD = Emergency Shutdown Package FAT = Factory Acceptance Test FMECA = Failure Mode Effect and Criticality Analysis HXT = Horizontal Xmas Tree ISO = International Standards Organization IWOCS = Intervention and Workover Controls LMRP = Lower Marine Riser Package LRP = Lower Riser Package LWRP = Lower Workover Riser Package (EDP & LRP) MSV = Multi-Service Vessel RV = Retainer Valve SCR = Steel Catenary Riser SIT = System Integration Test SSTT = Subsea Test Tree TH = Tubing Hanger TLP = Tension Leg Platform XT = Xmas Tree References

1. Jenman, C., “DP Performance and Problems Reviewed”, Offshore Engineer, February 1995.

2. Leeson, T., Richards, A., Wright, C., “Control Systems For Ultra-Deepwater Well Operations”, Oil

and Gas West Africa Conference, Houston, Texas, December 1999

3. Harrold, D., “Economic Impact of Slimbore and Drill Through Xmas Trees on Deepwater Subsea Developments”, OTC 14264, Offshore Technology Conference, May 2002

SI Metric Conversion Factors ft. x .3048 = m

8 OTC 15085

Operation Running StringDays Connected

to Well 3Probability of DP

IncidentConsequence of

FailureRun Conductor Housing Drill Pipe 1 Low LowRun HP Wellhead Drill Pipe 1 Low LowRun Casing Hangers Drill Pipe 1 Low LowRun Tubing Head Drill Pipe 1 Low LowRun Tubing Hanger Landing String 1 Low MediumRun HXT Tree Cap Drill Pipe 1 Low MediumRun Tree on Drill Pipe Drill Pipe 2 Medium MediumRun Tree on C/WO Riser C/WO Riser 2 Medium MediumFlow Test CXT C/WO Riser 10 High HighFlow Test HXT Landing String / SSTT 10 High HighCXT Thru-Tubing Intervention C/WO Riser 5 High HighHXT Thru-Tubing Intervention (Heavy) Landing String / SSTT 10 High High

Table 1 - Probability of DP Incidents and Associated Level of Consequence

Figure 1 – Frequency of DP Incidents Versus Exposure time

Frequency of DP Incidents Versus Exposure Time

0

200

400

600

800

1000

1200

1400

1600

1800

1 2 3 4 5 6 7 8 9 10

D ays C onnect ed t o W ell

2 Wells or Int. / Yr. 4 Wells or Int./ Yr. 6 Wells or Int. / Yr. 8 Wells or Int. / Yr. 10 Wells or Int ./ Yr.

OTC 15085 9

HFL

EFL

SCM

HXT BOP

LMRP

UTH

IWOCS UMBILICAL

MARINE RISER

Figure 4 – HXT Installation Mode

HXT SPOOL BODY

18 ¾ RE-ENTRY PROFILE

18 ¾ WELLHEAD CONNECTOR

Figure 5 – Deepwater HXT Configured For DP Installation

18 ¾ HIGH PRESSURE WELLHEAD HOUSING

38” CONDUCTOR HOUSING

RIGID LOCK MECHANISM

Figure 3 – 18 3/4 15K Deepwater Wellhead System

RIG TENSIONERS

FLUID BEARING

INTERMEDIATE JOINTS

TENSION JOINT

FLOWHEAD

BALES

TOP DRIVE RAILS

DOLLY FRAME

Figure 2 – Flowhead and Riser Tensioning Arrangement

10 OTC 15085

PIPE RAM

PIPE RAM

PIPE RAM

SHEAR RAM

BLIND SHEAR RAM

BLIND SHEAR RAM

LMRP CONNECTOR

ANNULAR

BOP CONNECTOR

WELLHEAD / TUBING HEAD / HXT

MARINE RISER

THRT

TUBING HANGER

SLICK JOINT

SPACER JOINT

EDC (OPTIONAL)

SHEAR JOINT

SPACER JOINT

ANNULAR SLICK JOINT

SPACER JOINT

SCM (OPTIONAL)

THRT

TUBING HANGER

SLICK JOINT

SSTT

EDC

SHEAR JOINT

SPACER JOINT

ANNULAR SLICK JOINT

SPACER JOINT

SCM (OPTIONAL)

RETAINER VALVE

THRT

TUBING HANGER

BOPSJ

LANDING STRING

DP HXT LANDING STRING

SLICK JOINT

MOORED TH INSTALLATION STRING DP TH INSTALLATION STRING

Figure 8 – HXT and CXT Installation Strings in DP BOP Stack

16 ¾ RE-ENTRY PROFILE

18 ¾ TREE CONNECTOR TUBING HANGER

18 ¾ RE-ENTRY PROFILE

Figure 7 – Deepwater CXT Configured For DP Installation

18 ¾ TUBING HEAD CONNECTOR

EDP

LRP

CXT

TUBING HEAD SPOOL

Figure 6 – Deepwater LWRP Configured For DP Operations