OTC 18646 Enabling Solutions for Deepwater Drilling Riser Management—A Critical Evaluation A.S. Westlake and K. Uppu, MCS
Copyright 2007, Offshore Technology Conference This paper was prepared for presentation at the 2007 Offshore Technology Conference held in Houston, Texas, U.S.A., 30 April–3 May 2007. 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, its officers, or members. Papers presented at OTC are subject to publication review by Sponsor Society Committees of the Offshore Technology Conference. 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. Write Librarian, OTC, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435.
Abstract As exploration activity increases and day rates increase for drilling vessels there is significant pressure on drilling contractors to push the limitations of both vessels and drilling equipment, as such deepwater drilling riser management has become a critical aspect of any well drilling operation. This is particularly the case in deepwater operations combined with potentially harsh environmental conditions (currents, wind, wave combinations) where maintaining operability is a potential problem as is maintaining riser integrity. There are several areas of technology development that may allow continued operations or planning of operations to allow minimal downtime related to environmental conditions. There are also several areas of key technology that could enable riser operations in deeper water depths. The items outlined will be assessed critically with respect to rig operations and highlight key areas that require development. Introduction It is accepted that for deepwater drilling riser analysis drilling contractors and operators adhere to the guidance provided by API RP16Q to define riser tensions and assess operability, hang-off, drift-off and weak point analysis, however each operator / drilling contractor may have procedures in place to enhance operability, maintain mean riser angles and so on. It is the intent of this paper to assess what procedures are in place as compared to what aspects are typically analyzed. The intent of the paper is to also offer a critical assessment of potential enabling technologies be they the deployment of fairings, composite auxiliary lines, riser materials, drilling riser management software or real time monitoring systems. Drilling Riser Management The operation of deepwater drilling riser systems are generally dependent upon the current regime at any particular
well location, with the most significant impact on riser response from the full depth current profile rather than just from surface current alone. It should also be noted that it is not sufficient to just address the drilling riser alone since interaction with the wellhead and conductor becomes considerably more important as tension in the riser increases. It is generally accepted that riser analysis allows operators and drilling contractors a perception of what potentially will influence riser operations during the drilling program. Riser operations being considered as the following: • • • • •
Open water operations Operability Hang-off performance Fatigue Running and retrieval
The main driver for good drilling riser management (see figure 1) practice is the concept that no drilling contractor wants to have to pull the riser in a storm, or leave it hanging from the spider / tensioners and hence there is pressure applied to provide a system robust enough to remain connected during a storm and preferably remain drilling ahead. In order to manage long strings of drilling riser it is accepted that certain strategies can be applied in an attempt to combat the loss of operability: • • • •
Control riser tension (increase to reduce LFJ angle) Control vessel position Spaceout modifications Alter riser drag (with fairings or otherwise)
In order to manage long strings of drilling riser in harsh environments, that may comprise high currents in combination with severe wave regimes, it is necessary for a vessel operating at a particular well location to have access to significant amounts of data related to drilling equipment and metocean conditions. These data may include the following:
2
• • • • • •
OTC 18646
Real time angle measurements (upper, lower and intermediate flex joints) Access to reliable acoustic Doppler current profiles Bathymetric charts Reliable advance (72 hour) weather forecasting of storms and currents Well specific riser management plan Operator well design
Riser Response Before any drilling riser is deployed a drilling contractor / operator will undertake a drilling riser response study based on the prevailing metocean conditions for a given well site based on the guidance of API RP 16Q [1] and AMJIG [2]. For connected operations emphasis is generally given to assessing the riser response due to currents since wave loading on any given vessel is unlikely to have a large influence on mean riser angles. The current drilling riser codes suggest that drilling downtime is likely to be incurred if mean riser angles exceed 2 degrees. In reality most drilling contractors place a more stringent requirement on their operations generally limiting mean angles to less than 1 degree. This more stringent angular limitation is designed to reduce wear in the system, particularly in lieu of the lower flex joint, although again in reality if the correct wear bushings are deployed then it is unlikely that key seating will occur across critical components of the system even above a 1 degree mean angle. This limitation is also designed to provide some margin against the wellhead not being perfectly vertical when installed. Conversely for disconnected operations wave induced vessel motions will tend to have the largest influence on riser response, although current drag load on the suspended riser string may also cause clashing issues with the diverter housing or otherwise. It is also understood that suspended risers are a low tension system and as such could be subject to significant fatigue damage from vortex induced vibration if allowed to hang free in relatively high currents. The effect of VIV would likely compound the drag on the riser since VIV increases the effective drag coefficient of the riser. It is accepted that running and retrieval operations are more than likely conducted in benign environmental conditions, however an emergency disconnect for a DP vessel may well be in relatively harsh conditions since the vessel will have lost station. For connected and disconnected operations there are already operating / operational procedures in place to try and manage long riser systems and these are discussed in the following section. Operational Techniques Prior to deploying a riser system a set of operational limits will be defined by each drilling contractor on a vessel and well specific basis. In addition to the documented limitations a set of procedures would also likely be drawn up that could potentially mitigate any problems, and hence a riser management plan is developed. Riser management as
previously stated can be split into several areas of which the intent of this paper is to only really assess three of the key issues (operability, hang-off and running and retrieval)., with most attention paid to connected operations. Connected Operations On a well specific basis a set of mechanical limitations will be prescribed for the riser system generally in relation to flex joint angles and tensioner / telescopic joint stroke. The riser spaceout may also be optimized to provide sufficient buoyancy to allow for tensioner capacity and sufficient in water weight such that the riser can be hung-off in at least the largest connected seastate without going into compression or clashing with the vessel. It would be considered normal practice where mean differential riser angle (allowing for wellhead being out of plumb) exceeds 1-degree and is less than 3-degrees with the same dynamic amplitude of +/- 0.50-degrees, that tripping operations (non-rotating, hoisting operations) would be carried out to secure the well and/or bring the drill string above the BOP rams. Following which operations will be suspended until it is confirmed that measured riser response is within the tolerances specified for resumption of operations. To assist in this decision making process a riser operability analysis would have been performed prior to spud of the well. As additional guidance for rig operating personnel, based on the analytical data the installation can be repositioned upcurrent (to improve lower angle), down-current (to improve upper angle) by active winching or biasing for DP installations. Riser tension may also be adjusted upwards within the rated capabilities of the tensioners and riser system to aid in the control of the mean riser angle and minimize the associated dynamic amplitude; however, riser tension will never be reduced below the API minimum recommended vertical tension for the location. It should also be considered that for the harsh environment dynamically positioned vessels there will likely be a limitation on the maximum and minimum tensions due to the anti-recoil system. It is clear that if the riser spaceout can be optimized to account for the requirements of the well and also to allow a significant amount of reserve tension over and above that required for the maximum mud weight then it should be possible to control riser angles with that tension. There are additional challenges associated with deepwater drilling riser management particularly for the connected drilling riser. There is more and more pressure applied now to carry out combined operations in that for development wells drilled from a MODU the rig may be required to deploy completions equipment, coiled tubing and or a test tree. These operations can only be performed under more stringent mechanical limits than just standard drilling due to the general requirement that the operator is unlikely to want to carry the cost of a sheared tree or string of coiled tubing. In order to take a critical look at whether the approaches above do increase operability, a generic 6000 ft WD case with connected riser with applied 10-year return period loop current was analyzed to provide comparative results. In the analytical work the effect of increasing tension and optimizing vessel offset from the well centre have been investigated.
3
Tables 1to 4 and figures 3 to 8 provide the analytical results of conducting the above operations in a 10-year loop current. The results provided indicate that increasing tension can have a significant impact on drilling riser angle, however this should be qualified in that the addition of tension also results in increased tension across the wellhead and into the conductor casing both statically and dynamically. Loss of stationkeeping for DP vessels leading to emergency disconnect should also be considered whilst developing the riser management plan, since this requires forced suspension of the drilling riser from the drill floor. Conclusion of Connected Parametric Study The results of the parametric study carried out for this section of the paper indicate some interesting trends for this water depth case at least. The increase in top tension applied to the riser system in the current regime applied reduces curvature in the system and therefore influences the angular rotations at both the top and the bottom of the system. It should also be noted that any increase in tension will also increase the load carried through the wellhead and conductor and any riser management plan must address this issue if applying additional tension is part of any mitigation measure prescribed. The reduction in curvature appears to have a profound effect on the upper flex joint and lower flex joint angles, for this current regime and water depth. In addition the effect is more significant for a riser that has been displaced to seawater when compared to the 12ppg mud case. The figures (3,4,5,6,7,8) also indicate that the reduced mass in the riser generates a lesser initial riser response. The conclusion above therefore confirms that displacement of the riser to seawater and addition of more tension may allow the rise to remain connected when it may have had to have been disconnected if more dense drilling fluid had remained in the system. In addition figures 3, 4 and 5 clearly show the effect of repositioning the vessel up current on the lower flex joint and moving down current on upper flex joint. The short study shows that techniques already employed on board drilling vessels are effective in reducing riser angles, possibly sufficiently to continue drilling or at least remain connected when the riser may otherwise have been disconnected. Critically though it should also be noted that additional tension can only be applied within the constraints of the tensioner system and also the constraints of the recoil system, as such the application of additional tension may be limited for a given rig and well location.
Disconnected Operations In many cases, contrary to connected operations long riser strings are deployed under controlled conditions. In combination with the operability analyses, a drilling contractor will establish through analyses the maximum environmental conditions during which the riser can be deployed or safely suspended. As such any string will only be deployed, or
OTC 18646
suspended, if an adequate weather window exists. For the emergency hang-off situation the riser string has to be designed for the maximum connected operating condition. The key issues for long suspended strings of riser are the potential for clashing with the diverter housing or vessel and avoiding the axial dynamic response that puts the riser in compression. More recently there have also been problems with relative axial motions of the auxiliary lines causing failure of auxiliary line seals. It is difficult to quantify a set of enabling solutions that would allow a riser string to be deployed or hung-off in environmental conditions outwith the original design of the system; however a few items for discussion are listed below: • • • •
Drift while running Reduce drag on the riser Vertical support through the moonpool Support arrangement
In order to minimize the effect of current on a riser string being deployed from a DP vessel it is often the case that to facilitate running, or retrieval, a vessel will be positioned such that it can drift onto location with the prevailing current. This minimizing the drag effect on the riser and hence avoids clashing issues. This also requires very careful planning since overshot of the wellhead can cause significant lost time as the vessel repositions for latch up. There must also be a favourable bathymetric corridor through which the riser can be run to avoid clashing with the seabed or other sub-sea infrastructure. Reduction of drag on the riser is discussed in the following section, suffice to say that it is possible through optimization of the position of buoyant riser joints and or the deployment of fairings to reduce hydrodynamic drag over the upper section of any riser string. Critically the time that it takes to run fairings often drives the decision not to run them and as such it is probably more prudent to try and optimize the position of the buoyant joints in the string. A major consideration when assessing the hang-off of long strings of drilling riser are the support arrangements (boundary conditions) at the top of the system. It is difficult to optimize the running and retrieval operations since the riser will always be supported by the blocks and then resting in the riser for make-up and break out of joint connections. In storm hang-off mode there are several options, traditionally the riser may be supported in the spider. However, to provide a more pliant load path following emergency disconnect the telescopic joint may be latched up and the riser allowed to remain supported by the tensioners and hook. The latter arrangement allows the vessel motions to be de-coupled from the riser and thus potentially avoiding exciting the riser axially and causing compression in the system or exceeding the hoisting capacity of the rig. This does not solve the issue of current loading on the riser which may still in these circumstances cause angular rotation at just below the drillfloor and potential clashing through the diverter and moonpool. A novel solution(s) to the problem of large rotation suspended riser strings is moving the point of rotation below
4
Andy Westlake, Kalyan Uppu
the keel or at least below the telescopic joint by the deployment of an intermediate flex joint. The intermediate flex joint solution can only really be an effective solution if the riser can also be laterally restrained through the moonpool. This lateral restraint solution has been attempted by a number of rigs with varying degrees of success, in addition the concept of having a riser guide system in the moonpool has also recently been investigated. It is important based on the above that a thorough management plan be developed which encompasses not only connected operations but also disconnected operations. This form of riser management document would have to incorporate a thorough understanding of the potential response of the riser string axially and laterally. Riser Hydrodynamic Drag Exposure to high currents results not only in high drag loads and riser angles, but increases possibility of vortexinduced vibration (VIV), observed as oscillation of the riser and resulting in accelerated fatigue damage of the string. It should also be noted that another problem associated with VIV is the increase in the effective drag coefficient of the riser string potentially resulting in larger deflections of the riser if lock in of response occurs. It should also be pointed out that riser vibrations are not always apparent, especially in long riser strings where vibration can be induced at mid-water column or near the mud line without apparent effect in the moon pool. Operationally therefore it is desirable to avoid vortex-induced vibration in the riser string through various means. In addition to the reduction in VIV response it may also be desirable to reduce hydrodynamic drag on the riser system. Fairings Riser fairings for example, are not primarily intended to suppress VIV, but rather improve riser operability in high currents by reducing drag load on the riser. However, effective reduction in VIV response also has the added benefit of reducing effective drag brought on by VIV. Strakes, in comparison, tend to counter the effects of VIV by disturbing water flow around the riser, but does little to reduce drag on the riser and in some cases actually increase the drag on the riser. Auxiliary lines and hoses can be independently excited by vortex induced vibration, resulting in fatigue damage or failure of hoses, umbilicals and small tubulars such as rigid conduits. A drilling contractor may dictate that a vessel caught in high currents with a vibrating drilling riser could as a control adjust the vertical tension upward incrementally (up to the maximum usable top tension (typically 0.90 x installed tension x 0.95). It should be noted that the vertical tension will likely be adjusted at the discretion of the onboard responsible parties and should be set only as high as required to mitigate vibration. Since it is difficult to actually see a riser vibrating in the moonpool, it would be a difficult call for rig personnel to decide if and when the drilling riser has discontinued from vibrating. It may also be possible to reduce response to a degree by offset of the installation slightly up-current or down-current, this will also effect riser angles and would therefore have to be considered carefully prior to performing this operation.
OTC 18646
A rig may also consider attempting to increase the reserve top tension that it can apply to the drilling riser by lightening the system weight during an extreme event. The action taken by the rig would be to displace the drilling fluid from the riser for sea water. This improves the effect of increased vertical tension by reducing the submerged weight of the riser contents. A similar analysis has been performed for this case with regard to riser angles rather than vibration response, thus taking the same riser model displaced to seawater and increasing tension to assess relative angles (see tables 1 and 2 and figures 3 to 8). In addition since fairings rather than strakes have been applied in the past to drilling risers for VIV suppression a critical evaluation of the effect of fairings on a string of riser parametric study has been performed factoring up and down the riser joint tangential drag coefficients and assessing the effect on angular rotation of the flex joints during exposure to a Gulf of Mexico 10-year loop current in 6000ft water depth The results of this drag parametric study can be seen in tables 5 and 6 and figures 9 to 14. Conclusion of Drag Parametric Study The results of the drag parametric study indicate some interesting trends for this water depth case at least. It is clear that reducing drag over the full length of the riser has some impact on lower flex joint angle, however there is a significant impact on the upper flex joint. This is significant in that as water depths increase the hydrodynamic drag effect on the riser starts to become limited to a large degree over a limited section of the riser string. This effect has been assessed by varying the length over which the drag coefficient is reduced during the analysis. What is most noticeable about these analyses are that the results for varying the drag coefficient over the full length of the riser are actually the same as if the drag coefficient is only varied over the upper portion of the riser. These results appear intuitive in that with a sheared current profile (Brazil, Gulf of Mexico) the majority of drag load will likely be concentrated over the upper portion of the riser. Critically if we assess the drag parameters as published by Shell for their tail fairings (see table 6) and assess based what Cd should be applied analytically for a set of currents it is possible to come to the general conclusion that higher current velocities (hence higher Reynolds numbers) will result, if the riser is faired, or if buoyant joints are run over the upper portion of the riser exposed to the highest current that significant savings in upper flex joint angle can be achieved. Based on the analytical work performed for this paper, altering the drag coefficient from 1.0 to 0.7 likely provides a saving of 25% on upper angle for a highly sheared loop current. The ultimate conclusions drawn from the analytical work performed during preparation of this paper are as follows: • •
Reducing drag coefficient over the region of drilling riser subject to high currents can increase operability in that it is possible to reduce upper flex joint angle. Fairings have been proven through model tests and experience to reduce the VIV response and the increased drag associated with a vibrating drilling riser. At high Reynolds numbers the benefit of running fairings (based
5
OTC 18646
on Shell Tail fairings) could be dramatic. It should also be considered that at high Reynolds numbers buoyancy modules alone may also provide similar savings in drag coefficient over the upper sections of the riser string. This conclusion is purely based on guidance provided by API RP 16Q [1]
comparatively small since the ability to revert to conventional auxiliary lines is retained. Also of concern is the trend toward higher anticipated mud weights in ultra-deep water wells which not only increase the tension requirement but also result in high local loads in the riser couplings along the length of the riser string.
Hardware It is obvious that a combination of factors assist in increasing operability and hence managing strings of riser in deepwater and challenging environmental conditions. However, one purpose of this paper was to also discuss the potential use of emerging technologies in marine drilling riser systems to meet the challenges of drilling riser management during the coming years in the deep-offshore drilling industry. Drilling operations in the US Gulf of Mexico (US GOM) in a water depth of 10,011 feet by the Discoverer Deep Seas in November 2003 have provided indications that the ability to perform efficiently and successfully in water depths beyond 10,000 feet requires study of new technologies to enhance the capabilities of existing equipment in lieu of simply scaling up existing systems to meet the increased capability demands, since this is potentially cost prohibitive. The issues with the conventional steel marine drilling riser appear principally to be mass and wet weight, thus many rigs become tension limited and thus have little margin for increasing tension to try and reduce angles and increase operability. Thus, the ability to reduce the mass supported by the tensioner system should not only allow the advanced 5th generation rigs to push the water depth envelope out beyond 10 or 11,000ft but also allow some of the lesser capable rigs to move beyond their limiting water depths and still be able to manage their drilling risers effectively. Several new or emerging technologies are considered as candidates for a critical assessment for this paper. These include but are not limited the following:
Subsequently, the equivalent mass between a standard slick joint of steel riser joints versus the other solutions has been assessed. It can be seen that composite auxiliary lines and even titanium, although to a lesser degree offer significant weight savings. This has a direct impact on the mass to be supported by a rigs tensioner system and hence the amount of reserve tension that can be applied to increase operability. This is complicated to some degree by the fact that it is desirable to tune buoyancy requirements in order that minimal top tension is applied to support the riser and mud column while maintaining sufficient in water weight should the riser require to be hung-off. Tables 7 and 8 indicate that due to the additional buoyancy of all three material types a reduction in the buoyancy diameter and lift characteristics may be achieved. This in itself has a profound effect on the drag characteristics of a long string of riser in deepwater that is deployed with a significant number of buoyant joints in the region of highest currents in any given water column. It is suggested therefore that not only does substituting the auxiliary lines for another material reduce the mass of the riser system it may also go some to reducing the drag load on the system. From this assessment and previous work performed by Transocean [4] and Vetco [7] it is possible to conclude the following:
•
• • • • •
Composites – all composite riser and / or composite auxiliary lines Aluminium riser / auxiliary lines Titanium riser / auxiliary lines Surface BOP (already been deployed in deep water depths from a DP MODU) Free-standing riser
While all of these options have real benefits, some of which are yet to be fully quantified, since surface BOP, aluminium riser and the FSR concept have already been studied in depth as such a critical focus in this paper has been how much weight can be saved for a particular concept and hence what is the implication for reserved tension and hence operability (riser management). In this paper the use of different materials for the peripheral lines on a steel riser tube has been concentrated upon. This decision has been made since the replacement of existing auxiliary lines on an existing deep water riser system represents a substantial reduction in capital investment over the purchase of an entirely new riser system (different material or otherwise). Additionally, for the drilling contractor risk is
Conclusion from Hardware Assessment The results of the hardware assessment indicate the following: •
• • •
Comparable connected operability should be achievable with a reduction in required top tension, eliminating the need for tensioner capacity and corresponding substructure upgrades for some ultra-deep water drilling units. In addition to the conclusion above this would free up more reserve tension for use in managing riser angles. The potential reduced wet weight of the hybrid riser string, combined with a reduced tension requirement should result in lower coupling loads. The potential for reduction in buoyancy diameters over the upper portion of the string should lead to enhanced drag characteristics and hence better operability and riser management.
A potential criticism of the hardware enabling options may be that it is unlikely that a drilling contractor will take a step out from traditional equipment until a test case or qualification has been performed to prove reliability. This statement is made since the pressure at present is to remain drilling and connected for as long as possible. It may also be the case that the wall thickness required for the materials other than steel to
6
Andy Westlake, Kalyan Uppu
meet the design requirements may make the options less desirable. Other Hardware Options Since riser management in deepwater is generally concerned with maintaining operability and riser integrity some novel solutions have been applied recently for deep water locations where riser component integrity due to high current loading is an issue. What is meant can be illustrated by the fact that during high currents riser deflections can lead to lower angles that may result in contact between the internal diameter of the riser / LFJ / LMRP / BOP and the drillpipe within it causing high contact forces and hence wear at any given contact location. The API RP 16Q document suggests that once a 2 degree mean lower flex joint angle is attained rotation of the drillpipe within the riser should be halted and the riser and drilling equipment be prepared for potential disconnected operations. The 2 degree angle limitation is an estimate of the point of contact and hence the point at which wear commences. Good drilling practice dictates that wear bushings should be in place across the critical components of the LMRP and BOP stack such that key areas are not key seated. It is considered that the 2 degree mean angle was chosen to also account for the fact that the wellhead and hence BOP at most drilling locations are rarely installed purely vertical. In considering the mean lower flex joint angle as a limitation to drilling due to wear, then it should be noted that most drilling contractors stipulate a mean lower angle limitation of 1 degree or less for drilling operations in an attempt to maintain equipment integrity. Pioneer Natural resources have published information regarding one solution to this problem, a passive solution rather than active management of angles. By passive the authors mean that the solution applied by Pioneer to exceed the angular limitations of their drilling contractor did not require that the vessel apply an active means of controlling angle (tension, vessel offset etc). The “enabling” solution applied by Pioneer Natural Resources was to install non-rotating drillpipe protectors on each joint of drillpipe. The protectors comprise sleeves made from tough, but flexible polymer that are free to rotate on the pipe. These pipe protectors have generally, to date at least been applied to reduce torque, drag and casing wear in high angle wells. The protectors deployed had outside diameters greater than the diameter of the drillpipe tool joints and hence provide a stand-off between the most damaging component of the pipe and the riser internal wall. During loop current exposure at the well location drilling operations continued even with lower riser angles up to and exceeding 2 degrees. Although this is a passive system it appears to be an effective riser management solution in that with the drillpipe protectors deployed the vessel in question (moored) did not have to try and apply significant additional top tension (assuming that it was not operating at the limit of its tensioner system), nor did the rig have to try and actively winch around location to try and free up angle to continue drilling. It should be considered that although the above is a potential solution to some drilling riser management issues, wear of the internal wall of the riser and other key components
OTC 18646
is very difficult to quantify. Anecdotal evidence suggests that removal of the lower flex joint wear bushing during drilling operations can result in key seating or drilling right through the flex element. There has also been significant amounts of work performed to assess critical contact angles at which point contact forces start to rise and wear commences within the system, however quantifying how much wear is going to occur and where is very difficult. This solution appears to have been a success for Pioneer Natural Resources however, the authors would be surprised if many drilling contractors would be willing to deploy the same type of system. Passive Solutions In addition to the active, hardware and passive hardware solutions to managing deepwater drilling riser systems the recent development of several on-board operational simulation software packages and riser monitoring systems has enabled enhanced planning of rig and drilling operations. In itself these do not appear to be significant contributors to the whole drilling riser management plan for a well or sequence of wells. However, the reliable planning of operations in combination with reliable weather forecasting can be a valuable drilling riser management tool. MCS has developed the following tools which can be utilized to manage offshore operations and provide valuable input into the decision making process on-board any drilling vessel. The software packages are the following: • •
IRIS 3D™ – full real time monitoring coupled with riser management software. DeepDrift™ – drift off assessment for DP vessels
The capabilities of each of these packages are outlined below with the riser management benefits of each summarized: IRIS RMS 3D™ This system is an on-board Riser Management System (RMS) that provides an integrated full real-time riser response monitoring system coupled to a state of the art FE analysis tool. The IRIS system can provide the following analyses in real time: • • • • • •
Operability Hang-off Running and Retrieval Drift-off analyses Fatigue tracking VIV response
It can be seen from the break down of capabilities that there are significant benefits from the system from both a riser operating stand-point and an integrity management tool. Of most importance in terms of this paper are the capabilities of the operability analysis module. Not only does the software calculate the mechanical limits of the riser system
7
OTC 18646
for a given monitored set of environmental conditions, it will utilize these data to provide the following: • • • • •
Recommended vessel position(s) to optimize specific riser system parameters Maximum and minimum top tension limits on the riser Optimum total riser top tension and optimum split of tension between tensioner tension and hook load Maximum stress in riser joints and location (joint) where this occurs Recommended red and yellow watch circles for DP vessel
If we take these items in the context of the rest of this paper then it is clear that the IRIS RMS™ software is taking the “guesswork” out of riser management. This means that for rig personnel there is a relatively easy decision tree to follow, in that the software is providing the optimum solution in order to keep the vessel drilling and maintain riser integrity. DeepDrift™ This system is an on-board drift-off simulator / prediction program. This software is designed to predict the alert offsets for a given DP MODU’s station loss scenarios. The program was developed in conjunction with “GlobalSantaFe” and is designed to operate in the offline mode only. By stipulating that the software remains offline, the requirement is then that the DP operator onboard the rig takes responsibility for the environmental data input. There is no integration with any onboard sensors or data acquisition systems. Most recently this program has been enhanced with a drift while running module and a running and retrieval module. The software incorporates a fully-couple FE model of the vessel, drilling riser and well system. The FE engine from Flexcom™ acts as the analysis tool and is run to simulate the behaviour of the riser and vessel during the loss of power on board the vessel. Critical riser parameters are monitored during the analysis to determine where the yellow and red watch circles should be in relation to the point of disconnect. The results of each simulation allow rig personnel to make informed decisions about when / whether emergency disconnect will be required in any given environment. The ultimate driver for this type of tool is that the prevailing environmental conditions on any given day at any location will not reflect the conservative design environments applied in the riser analysis. By allowing the user to input actual environmental data in effect allows the expansion of watch circles during benign conditions. Conditions during which, with no simulation software onboard, emergency disconnect may be forced if station loss occurs. In reality decision making time is extended during benign conditions and hence the avoidance of unnecessary disconnects of the LMRP, and associated loss of drilling time can be avoided. GlobalSantaFe cite that when combined with appropriate operating decision making processes this system saved them more than $2million on one well. The additional enhancements to the software away from just the drift off analyses are also designed to assist in riser management and operational planning by allowing simulation of running riser drifting or otherwise. By simulating
prevailing conditions while the riser is being run the software provides the appropriate drift speed and path and vessel position to allow latch up to the wellhead without overshoot and the associated lost time repositioning the rig to attempt to latch up again. Conclusions Riser management in deepwater, high current and harsh environments can be achieved through good operating procedures, operations planning, data acquisition and weather forecasting. As rigs move out to deeper water depths then the requirement for reducing riser string weight, to fit with existing tensioner and recoil systems may have a significant impact on the application of new technology to enable connected and disconnected drilling riser operations. It is also considered that the application of real time monitoring systems in conjunction with state of the art simulation software will allow access to significant quantities of riser response data for analytical model calibration. In addition riser management will be assisted by the ability to reliably simulate what the riser response will be for a given set of forecast data. Tried and tested methods of riser management such as repositioning the rig and pulling more tension appear effective within the constraints of the vessels equipment, analytically at least. It is also considered the possibility of reducing the drag on any given riser system particularly over sections exposed to high currents can have a dramatic effect. Finally, good riser management moving into the future for deeper water depths will likely require a full combination of the techniques and systems described in this paper in order for rigs to maintain operability and riser integrity.
References [1] American Petroleum Institute: “Recommended Practice for Design, Selection, Operation and Maintenance of Marine Drilling Riser Systems (API RP16Q),” American Petroleum Institute (Nov. 1993). [2] Report Prepared for the Atlantic Margin Joint Industry Group (AMJIG) “Deepwater Drilling Riser Integrity Management Guidelines” October 1998 [3] American Petroleum Institute: “Bulletin on Formulas and Calculations for Casing, Tubing, Drill Pipe and Line Pipe Properties (API Bulletin 5C3),” American Petroleum Institute (Oct. 1994). [4] Darrel K. Pelley, Riddle E. Steddum, P.E., Andrew S. Westlake “Mooring and Riser Management In Ultra-Deep Water and Beyond” SPE/IADC SPE-92616-PP, February 2005 [5] Riddle Steddum “The Management of Long Suspended Strings of Tubulars from Floating Drilling Vessels”, Offshore
8
Andy Westlake, Kalyan Uppu
Technology Conference, OTC 15235, Houston, Texas 2003
[6] Douglas B. Johnson, Donald Baldwin, “Composite Choke and Kill Lines”, Offshore Technology Conference, OTC 14020, Houston, Texas 2002 [7] W.F Andersen, O. Burgdorf, Jr., T.F. Sweeney “Comparative Analysis of 12,500ft Water Depth Steel and Advanced Composite Drilling Risers”, Offshore Technology Conference, OTC 8732, Houston, Texas 1998
OTC 18646
Figure 1 Riser Management Definition Flow Chart
Fatigue Fatigue -Connected -Connected -Unconnected -Unconnected
Operability Operability •Connected •Connected •Unconnected •Unconnected
Slip Joint / Slip Joint / Tensioner Stroke Tensioner Stroke
Riser Angles Riser Angles
Riser Tension Riser Tension
Installation Installation Planning Planning Riser Running/Retrieval Riser Running/Retrieval Equip. Running/Retrieval Equip. Running/Retrieval
ADCP ADCP
Predictive Planning Predictive Planning Measured Environment Measured Environment Simulated Environment Simulated Environment
Position Position Optimization Optimization
VIV Prediction VIV Prediction
On-BoardSimulation Simulation On-Board (Software) (Software)
Etc. Etc.
Mitigation Mitigation • Fairings • Fairings • Angle Control • Angle Control
Real-Time Real-Time Monitoring Monitoring
Riser Vibration Riser Vibration
Operability Operability Planning Planning
Operations Operations Planning Planning
Riser Response Riser Response Prediction Prediction
Seal Tests Seal Tests
IntegrityAssurance: Assurance: Integrity MechanicalQualification Qualification Mechanical
Offshore Offshore
Connector Tests Connector Tests
IntegrityAssurance: Assurance: Integrity Analytical Analytical
Onshore Onshore
RiserManagement Management Riser
9 OTC 18646
10
Andy Westlake, Kalyan Uppu
OTC 18646
10 Yr Loop Current Profile
0.0
0.5
1.0
1.5
2.0
2.5
3.0
3.5
-300
-800
-1300
Elevation(ft)
-1800
-2300
-2800
-3300
-3800
-4300
Current Velocity (knots)
Figure 2 Representative 10-year Loop Current Profile
4.0
11
OTC 18646
Tension
8.56 ppg UFJ 700 800 900 1000 1100 1200 1300 1350 1400 1500 1600 1700
Tension
8.56 ppg LFJ 700 800 900 1000 1100 1200 1300 1350 1400 1500 1600 1700
Offset (% WD) -14 1.184 0.058 0.819 1.5 2.078 2.566 2.975 3.139 3.31 3.619 3.891 4.14 2
-12 2.019 0.904 0.037 0.65 1.214 1.686 2.087 2.266 2.432 2.734 2.999 3.214 2
-10 2.811 1.747 0.91 0.24 0.374 0.818 1.208 1.382 1.544 1.837 2.095 2.325 2
-8 3.627 2.592 1.779 1.128 0.592 0.066 0.309 0.477 0.634 0.911 1.161 1.385 2
-6 4.401 3.399 2.624 1.998 1.483 1.051 0.684 0.52 0.367 0.089 0.154 0.372 2
-4 5.287 4.319 3.567 2.855 2.367 1.959 1.611 1.455 1.31 1.048 0.817 0.611 2
-2 5.992 5.085 4.379 3.814 3.35 2.961 2.63 2.483 2.345 2.096 1.877 1.682 2
0 6.807 5.949 5.284 4.751 4.315 3.95 3.641 3.503 3.374 3.143 2.939 2.758 2
2 7.566 6.762 6.14 5.644 5.239 4.902 4.616 4.489 4.371 4.158 3.972 3.807 2
4 8.426 7.66 6.938 6.48 6.108 5.799 5.538 5.422 5.315 5.122 4.953 4.805 2
6 9.069 8.36 7.815 7.384 7.033 6.744 6.5 6.392 6.292 6.113 5.956 5.819 2
8 9.811 9.145 8.514 8.121 7.803 7.55 7.328 7.23 7.14 6.978 6.837 6.714 2
10 10.49 9.764 9.3 8.949 8.652 8.408 8.203 8.113 8.029 7.88 7.75 7.637 2
2 0.171 0.002 0.083 0.128 0.155 0.169 0.175 0.177 0.178 0.178 0.175 0.171
4 0.694 0.711 0.697 0.668 0.635 0.601 0.568 0.553 0.538 0.509 0.482 0.457
6 1.557 1.425 1.307 1.203 1.111 1.03 0.959 0.926 0.895 0.838 0.788 0.741
8 2.41 2.132 1.915 1.736 1.586 1.458 1.348 1.298 1.252 1.167 1.092 1.025
10 3.254 2.835 2.517 2.264 2.056 1.882 1.734 1.667 1.605 1.493 1.394 1.306
Offset (% WD) -14 6.864 5.579 4.715 4.087 3.606 3.225 2.915 2.78 2.656 2.436 2.248 2.085
-12 6.068 4.913 4.139 3.578 3.152 2.814 2.539 2.42 2.311 2.118 1.953 1.809
-10 5.262 4.236 3.553 3.063 2.692 2.398 2.16 2.057 1.963 1.797 1.655 1.532
-8 4.44 3.549 2.961 2.541 2.225 1.978 1.777 1.691 1.612 1.473 1.354 1.252
-6 3.607 2.854 2.363 2.015 1.755 1.553 1.391 1.321 1.257 1.146 1.051 0.97
-4 2.757 2.148 1.756 1.484 1.282 1.126 1.002 0.949 0.901 0.817 0.747 0.686
-2 1.903 1.438 1.147 0.949 0.804 0.695 0.611 0.575 0.543 0.487 0.441 0.401
0 1.038 0.723 0.534 0.41 0.325 0.264 0.217 0.199 0.182 0.156 0.133 0.115
Tables 1 and 2 6000ft WD riser 8.56ppg mud weight, effect of varying tension and vessel offset
12
Andy Westlake, Kalyan Uppu
Tension
12 ppg UFJ 700 800 900 1000 1100 1200 1300 1350 1400 1500 1600 1700
Tension
12 ppg LFJ 700 800 900 1000 1100 1200 1300 1350 1400 1500 1600 1700
OTC 18646
Offset (% WD) -14 3.515 2.011 0.808 0.09 0.843 1.457 1.973 2.201 2.387 2.774 3.114 3.408 2
-12 4.189 2.708 1.523 0.606 0.108 0.704 1.214 1.433 1.635 2 2.295 2.579 2
-10 4.82 3.307 2.135 1.291 0.613 0.054 0.404 0.668 0.861 1.208 1.513 1.759 2
-8 5.388 3.895 2.789 2.002 1.36 0.828 0.38 0.182 0.071 0.389 0.679 0.935 2
-6 5.856 4.496 3.429 2.692 2.09 1.592 1.171 0.985 0.811 0.498 0.23 0 2
-4 6.36 5.054 4.165 3.471 2.908 2.349 1.961 1.789 1.629 1.34 1.087 0.862 2
-2 6.799 5.706 4.763 4.132 3.621 3.198 2.84 2.682 2.534 2.268 2.034 1.827 2
0 7.323 6.181 5.45 4.878 4.415 4.031 3.708 3.564 3.431 3.19 2.98 2.794 2
2 7.609 6.738 6.088 5.579 5.168 4.827 4.54 4.413 4.296 4.084 3.899 3.736 2
4 8.116 7.375 6.669 6.226 5.868 5.572 5.323 5.213 5.111 4.928 4.769 4.629 2
6 8.378 7.81 7.33 6.943 6.629 6.369 6.151 6.054 5.965 5.81 5.67 5.547 2
8 8.725 8.334 7.817 7.5 7.239 7.033 6.85 6.769 6.694 6.56 6.444 6.365 2
10 9.02 8.803 8.397 8.153 7.935 7.753 7.6 7.532 7.469 7.357 7.281 7.194 2
2 1.335 0.198 0.08 0.183 0.227 0.244 0.249 0.248 0.246 0.24 0.233 0.225
4 2.521 1.676 1.366 1.173 1.035 0.929 0.842 0.805 0.77 0.709 0.656 0.61
6 6.286 3.532 2.635 2.152 1.836 1.607 1.431 1.357 1.29 1.174 1.076 0.993
8 9.829 5.34 3.896 3.126 2.633 2.283 2.018 1.907 1.808 1.637 1.495 1.374
10 13.18 7.106 5.128 4.083 3.418 2.95 2.597 2.451 2.32 2.096 1.91 1.752
Offset (% WD) -14 27.17 14.17 9.743 7.459 6.059 5.099 4.399 4.115 3.863 3.44 3.096 2.81
-12 24.3 12.57 8.589 6.556 5.308 4.458 3.84 3.588 3.367 2.994 2.691 2.441
-10 21.53 10.96 7.428 5.636 4.545 3.806 3.27 3.056 2.865 2.543 2.283 2.068
-8 18.63 9.281 6.229 4.697 3.77 3.147 2.696 2.514 2.356 2.088 1.871 1.693
-6 15.64 7.55 5.008 3.744 2.987 2.48 2.117 1.97 1.842 1.627 1.455 1.313
-4 12.35 5.776 3.755 2.774 2.192 1.807 1.531 1.421 1.325 1.165 1.036 0.932
-2 8.88 3.94 2.493 1.797 1.391 1.126 0.94 0.867 0.803 0.698 0.615 0.548
0 5.151 2.084 1.21 0.809 0.584 0.442 0.346 0.31 0.279 0.229 0.191 0.162
Tables 3 and 4 6000ft WD riser 12ppg mud weight, effect of varying tension and vessel offset
13
OTC 18646
UFJ & LFJ Angle vs. Top Tension Vessel Offset = 0% WD; Mud Weight = 8.56 ppg Limits: UFJ = 2 deg, LFJ = 1 deg 8.0
LFJ Angle UFJ Angle LFJ Limit UFJ Limit
7.5 7.0 6.5 6.0 5.5
Angle (deg)
5.0 4.5 4.0 3.5 3.0 2.5 2.0 1.5 1.0 0.5 0.0 700
800
900
1000
1100
1200
1300
1400
1500
1600
1700
Top Tension (kips)
Figure 3 Change Flex Joint Angles as Function of Increasing Vertical Top Tension 0% WD Offset UFJ & LFJ Angle vs. Top Tension Vessel Offset = -4% WD; Mud Weight = 8.56 ppg Limits: UFJ = 2 deg, LFJ = 1 deg 8.0
LFJ Angle UFJ Angle LFJ Limit UFJ Limit
7.5 7.0 6.5 6.0 5.5
Angle (deg)
5.0 4.5 4.0 3.5 3.0 2.5 2.0 1.5 1.0 0.5 0.0 700
800
900
1000
1100
1200
1300
1400
1500
1600
1700
Top Tension (kips)
Figure 4 Change in Flex Joint Angles as Function of Increasing Vertical Top Tension Zero -4% of WD Vessel Offset
14
Andy Westlake, Kalyan Uppu
OTC 18646
UFJ & LFJ Angle vs. Top Tension Vessel Offset = 4% WD; Mud Weight = 8.56 ppg Limits: UFJ = 2 deg, LFJ = 1 deg 8.0
LFJ Angle UFJ Angle LFJ Limit UFJ Limit
7.5 7.0 6.5 6.0 5.5
Angle (deg)
5.0 4.5 4.0 3.5 3.0 2.5 2.0 1.5 1.0 0.5 0.0 700
800
900
1000
1100
1200
1300
1400
1500
1600
1700
Top Tension (kips)
Figure 5 Change in Flex Joint Angles as Function of Increasing Vertical Top Tension Zero +4% of WD Vessel Offset UFJ & LFJ Angle vs. Top Tension Vessel Offset = 0% WD; Mud Weight = 12 ppg Limits: UFJ = 2 deg, LFJ = 1 deg 8.0
LFJ Angle UFJ Angle LFJ Limit UFJ Limit
7.5 7.0 6.5 6.0 5.5
Angle (deg)
5.0 4.5 4.0 3.5 3.0 2.5 2.0 1.5 1.0 0.5 0.0 700
800
900
1000
1100
1200
1300
1400
1500
1600
1700
Top Tension (kips)
Figure 6 Change in Flex Joint Angles as Function of Increasing Vertical Top Tension Zero 0% of WD Vessel Offset
15
OTC 18646
UFJ & LFJ Angle vs. Top Tension Vessel Offset = 4% WD; Mud Weight = 12 ppg Limits: UFJ = 2 deg, LFJ = 1 deg 8.0
LFJ Angle UFJ Angle LFJ Limit UFJ Limit
7.5 7.0 6.5 6.0 5.5
Angle (deg)
5.0 4.5 4.0 3.5 3.0 2.5 2.0 1.5 1.0 0.5 0.0 700
800
900
1000
1100
1200
1300
1400
1500
1600
1700
Top Tension (kips)
Figure 7 Change in Flex Joint Angles as Function of Increasing Vertical Top Tension Zero +4% of WD Vessel Offset
UFJ & LFJ Angle vs. Top Tension Vessel Offset = -4% WD; Mud Weight = 12 ppg Limits: UFJ = 2 deg, LFJ = 1 deg 8.0
LFJ Angle UFJ Angle LFJ Limit UFJ Limit
7.5 7.0 6.5 6.0 5.5
Angle (deg)
5.0 4.5 4.0 3.5 3.0 2.5 2.0 1.5 1.0 0.5 0.0 700
800
900
1000
1100
1200
1300
1400
1500
1600
1700
Top Tension (kips)
Figure 8 Change in Flex Joint Angles as Function of Increasing Vertical Top Tension Zero -4% of WD Vessel Offset
16
Andy Westlake, Kalyan Uppu
Normal Drag 0.00 0.10 0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00 1.10
Tangential Drag 0 0 0 0 0 0 0 0 0 0 0 0
Normal Inertia 2.00 2.00 2.00 2.00 2.00 2.00 2.00 2.00 2.00 2.00 2.00 2.00
Full Riser Varied UBJ Angle LBJ Angle (degrees) (degrees) 0.075 0.000 0.418 0.000 0.794 0.016 1.172 0.036 1.550 0.052 1.927 0.068 2.303 0.099 2.680 0.101 3.054 0.121 3.428 0.132 3.801 0.144 4.172 0.158
Added Mass 0 0 0 0 0 0 0 0 0 0 0 0
OTC 18646
Lower Half Varied UBJ Angle LBJ Angle (degrees) (degrees) 3.693 0.113 3.704 0.116 3.715 0.121 3.725 0.127 3.736 0.131 3.747 0.131 3.757 0.153 3.768 0.158 3.779 0.162 3.789 0.167 3.801 0.144 3.811 0.148
Upper Half Varied UBJ Angle LBJ Angle (degrees) (degrees) 0.158 0.025 0.516 0.039 0.882 0.05 1.249 0.061 1.616 0.075 1.981 0.103 2.347 0.102 2.712 0.115 3.076 0.125 3.439 0.136 3.801 0.144 4.161 0.157
Table 5 Effect of varying drag coefficient on Riser Angles
Full Riser Varied (0% Offset) 4.50 4.00
UBJ Angle
3.50 3.00 2.50 2.00 1.50 1.00 0.50 0.00 0.0
0.2
0.4
0.6
0.8
1.0
1.2
1.0
1.2
Norm al Drag
Full Riser Varied (0% Offset) 0.18 0.16
LBJ Angle
0.14 0.12 0.10 0.08 0.06 0.04 0.02 0.00 0.0
0.2
0.4
0.6 Norm al Drag
Figure 9 and 10 Effect of varying drag over the full length of the riser
0.8
17
OTC 18646
Lower Half Varied (0% Offset) 4.50 4.00
UBJ Angle
3.50 3.00 2.50 2.00 1.50 1.00 0.50 0.00 0.0
0.2
0.4
0.6
0.8
1.0
1.2
Norm al Drag
Lower Half Varied (0% Offset) 0.18 0.16 0.14 LBJ Angle
0.12 0.10 0.08 0.06 0.04 0.02 0.00 0.0
0.2
0.4
0.6 Norm al Drag
Figure 11 and 12 Effect of varying drag over the lower half of the riser
0.8
1.0
1.2
18
Andy Westlake, Kalyan Uppu
OTC 18646
Upper Half Varied (0% Offset) 4.50 4.00
UBJ Angle
3.50 3.00 2.50 2.00 1.50 1.00 0.50 0.00 0.0
0.2
0.4
0.6
0.8
1.0
1.2
1.0
1.2
Norm al Drag
Upper Half Varied (0% Offset) 0.18 0.16 0.14 LBJ Angle
0.12 0.10 0.08 0.06 0.04 0.02 0.00 0.0
0.2
0.4
0.6
0.8
Norm al Drag
Figure 13 and 14 Effect of varying drag over the upper half of the riser
Reynolds Number (Re)
Drag Coefficient (Cd)
100,000
1.25 - 1.15
300,000
1.10 - 1.00
500,000
0.95 - 0.85
700,000
0.80 - 0.70
1,000,000
0.70 - 0.60
Note: Data Courtesy of Shell Global Solutions
Table 6 Typical tail fairing drag coefficients
19
OTC 18646
Joint Type Length Coupling Type Coupling Rating Coupling Yield
[feet]
Main Tube OD Tube Wall Thickness Tube Yield Strength C&K Lines ID C&K Lines OD C&K MAWP Mud Boost Line ID Mud Boost Line OD Boost MAWP
[inches]
Hydro Line OD / ID Hyd. Line MAWP Number of Hydro Lines
[inches]
Riser Steel Air Weight Auxiliary Line Dry Weight
[pounds]
Riser Steel Wet Weight Auxiliary Line Wet Weight
[pounds]
[kips] [ksi]
[inches] [ksi] [inches] [inches] [psi] [inches] [inches] [psi]
[psi]
[pounds]
[pounds]
Steel / Aluminium
Steel / Titanium
All-Steel 75 H 3,500 80
75 H 3,500 80
75 H 3,500 80
75 H 3,500 80
21.500 1.000 80.0 4.500 6.625 15,000 3.826 4.500 6,000 3.50 / 2.624 5,000 1
21.500 1.000 80.0 4.500 6.625 15,000 3.826 4.500 6,000
21.500 1.000 80.0 4.500 6.625 15,000 3.826 4.500 6,000
21.500 1.000 80.0 4.500 8.000 15,000 3.826 4.500 6,000
3.50 / 2.624 5,000 1
3.50 / 2.624 5,000 1
3.50 / 2.624 5,000 1
24212 12001
24212 4504
24212 7311
24212 4409
21050 10434
21050 2794
21050 5646
21050 2845
Steel/Comp
Table 7 Characteristic weights of slick riser joints woth varied auxiliary line material properties Joint Type Slick Joint, All Steel Slick Joint, Comp. Lines Slick Joint, AL. Lines Slick Joint, Ti. Lines
[pounds] [pounds] [pounds] [pounds]
Dry Weight
Wet Weight
36,213 28,621 28,716 31,523
31,484 23,896 23,844 26,696
Table 8 Characteristic weights of slick riser joints woth varied auxiliary line material properties
20
Andy Westlake, Kalyan Uppu
OTC 18646
RMS Top Level Control Module (TLCM) Riser Instrumentation1 Main Operator Interface
URSJ
RMS Main Window
LRSJ
Riser Input Module /Integrity Database Manager (RIM/IDM) Riser Stack-up Static Calculation Results
Tensioner System2
Riser Simulators
Riser Operating Simulator
Top Drive System
WOCS
Riser Model File
Simulator Control Module (SCM)
Riser/Vessel Drift-off Simulator
DP System Integrity Tracking Module
Notes:
1) Assumes instrumentation of 2 riser joints only, the URSJ and LRSJ. 2) At the time of writing, the availability of data from the tensioner system has yet to be confirmed.
Figure 15 IRIS RMS™ Flow chart overview
Figure 16 IRIS RMS™ Screen Shot
RMS Database
21
OTC 18646
Figure 17 DeepDrift™ Screen Shot