Drilling Riser Analysis Methodology
Contents
Running and Retrieve Analysis
The goal of running/retrieval analysis is to identify the limiting current environment that permits this operation. During this operation, the riser could be supported by the hook at 75 ft above the RKB (Rotary Kelly Bushing, a datum for measuring depth in an oil well), or it could be hanging in the spider. The critical configuration is the hook support because of its greater potential for contact between the joint and the diverter housing. The BOP is on the riser for deployment, and may not be on the riser if the riser is disconnected at the LMRP, in which case only the LMRP is on the riser. The hook is considered to be a pinned support with only vertical and horizontal displacement restraints. The riser may rotate about the hook under current loading. The limiting criterion is contact between a riser joint and the diverter housing. Static analysis is used to evaluate the effects of the current drag force. Wave dynamic action on the riser’s lateral motions is not considered.
Operability Analysis
The objective of the operability analysis is to define the operability envelope, for various mud weights and top tensions, per the recommendations of API RP 16Q. The operability envelope for the limiting criteria is computed using both static and dynamic wave analysis. The static analysis involves offsetting the rig upstream and downstream under the action of the current profile to find the limiting up and down offsets at which one limiting criterion is reached. Two current combinations are typically considered: background bottom and eddy bottom. Typically three mud weights are modeled with their respective top tensions. The procedure for the dynamic analysis is the same as that for the static analysis except that wave loading is added, and the analysis is carried in the time domain, using regular waves based on Hmax, and for at least five wave periods. The dynamic analysis predicts the maximum LFJ and upper flexjoint (UFJ) angles, which should be checked against their limiting values.
The limiting conditions for the flexjoint angles are typically as follows:
- Connected drilling for dynamic analysis:
- Upper flexjoint mean angle < 2 degrees; 4 degrees maximum;
- Lower flexjoint mean angle < 1 degree; 4 degrees maximum.
- Connected nondrilling:
- Upper flexjoint max angle < 9 degrees;
- Lower flexjoint max angle < 9 degree.
Note that the allowed limit for the upper and lower flexjoint angles is 1 degree for static analysis of connected drilling risers. Other limitations on the dynamic riser response are as follows:
- Riser von Mises stresses < 0.67 yield stress for extreme conditions;
- Riser connector strength;
- Tensioner and TJ stroke limit.
Limitations may also arise from loading on the wellhead and conductor system:
- LMRP connector capability;
- BOP flanges or clamps;
- Wellhead connector capacity;
- Conductor bending moment (0.8 yield stress).
For drilling, usually it is the mean angles of the LFJ (1 degree) and the UFJ (2 degrees) that determine the envelope. For nondrilling conditions, usually it is the maximum dynamic bending moment in the casing that controls the envelope.
Weak Point Analysis
Weak point analysis forms a part of the design process of a drilling riser system. The objective of a weak point analysis is to design and identify the breaking point of the system under extreme vessel drift-off conditions should the LMRP fail to disconnect. The riser system should be designed so that the weak point will be above the BOP. The basic assumption here is that all equipment in the load path is properly designed per the anufacturers’ specifications. The areas of potential weakness in a drilling riser system are typically:
- Overloading of the drilling riser;
- Overloading of connectors or flanges;
- Stroke-out of the tensioner;
- Exceedance of top and bottom flexjoint limits;
- Overloading of the wellhead.
Evaluation criteria for weak point analysis are derived for each potential weak point of the drilling riser system. The weak point criteria determine failure of the system. The evaluation criterion for stroke-out of the tensioners is typically the tensile strength (rupture) of the tensioner lines for each line. The maximum capacity of a padeye will be based on the load that causes yield in each padeye. The failure load capacity for a flexjoint typically corresponds to the maximum bending moment and tension combination that the flexjoint can withstand. This typically relates to additional loading following angular lock-out. The failure load capacity for standard riser joints and conductor joints is typically taken as the maximum combined tension and bending stress that the joint can withstand before exceeding the yield stress of the riser material. To eliminate uncertainty, a full time-domain weak point computer analysis may be conducted, as follows:
- Perform dynamic regular wave analyses for a selected combination of wind, waves, and currents and establish the dynamic amplification of the loads generated at potential weak points, especially at the wellhead connector and at the LMRP connector.
- Sensitivity analyses are typically performed to determine the effect on the weak point of varying the critical parameters such as mud weight and soil properties.
- Vessel offsets should range from the drilling vessel in the mean position to extreme vessel offsets downstream, as determined by a coupled mooring analysis.
- Following the offset analysis of the drilling riser system, the results will be processed to extract the forces and moments generated by the offset position. These are then compared with the corresponding evaluation criteria at potential weak points along the drilling riser system.
If the weak point is below the BOP, failure would have severe consequences in terms of well integrity, riser integrity, or cost. Then further analysis should be conducted to relocate the weak point to a position with less onerous consequences in the event of failure. One option that might be considered in this context is to redesign the capacity of the hydraulic connectors or bolted flanges/bindings in the drilling riser system such that the weak point occurs at one of those locations. In a mild environment, slow drift-off generates low static and dynamic moments on the wellhead because of the mild current and the low wave height. In a fast drift-off environment, the lower riser straightens out quickly before wave action magnifies the wellhead connector static moment when the tensioner strokes out. The suggested critical environment would be a combination of high current to generate a high static moment at the wellhead connector, high waves to cause high dynamic moments, and slow wind to generate slow drift.
Drift-Off Analysis
Drift-off analysis is a part of the design process for a drilling riser system on a DP rig. The objective of a drift-off analysis is to determine when to initiate disconnect procedures under extreme environmental conditions or drift-off/drive-off conditions. The analysis is performed for the drilling and the nondrilling operating modes. In each mode, the analysis will identify the maximum downstream location of the vessel under various wind and current speeds and wave height/period. The first task in a drift-off analysis is to determine the evaluation criteria by which the disconnect point will be identified. These criteria are based on the rated capacities of the equipment in the load path:
- Conductor casing, based on 80% of yield;
- Stroke-out of the tensioner/telescopic joint;
- Top and bottom flexjoints limits;
- Overloading of the wellhead connector;
- Overloading of the LMRP connector;
- Stress in the riser joint (0.67 of yield).
Coupled system analysis is used where the soil and casing, wellhead and BOP stack, riser, tensioner, and the vessel are all included in one model. Combinations of environmental actions (wind, current, and waves) are applied to the system, and the dynamic time-domain response is then computed. In this coupled vessel approach, the vessel drift-off (or vessel offset) is an output of the analysis. This approach, which accounts for soil/ casing/riser/vessel interactions, is more accurate than the uncoupled approach where the vessel offset is computed separately and then applied to the vessel drift curve to the riser model in a second analysis. Following the static and dynamic analyses of the drilling riser system, the disconnect point of the system is identified as follows:
- The vessel offset, for the specified environmental load conditions, that generates a stress or load equal to the disconnect criteria of the component is the allowable disconnect offset for that particular component.
- The allowable disconnect offset should be determined for each of the key components along the drilling riser system.
- Then the point of disconnect (POD) corresponds to the smallest allowable disconnect offset for all critical components along the drilling riser system.
- Once the vessel offset at which the riser must be disconnected has been determined, the offset at which the disconnect procedure must be initiated (red limit) will typically be based on 60 sec. This is the EDS time.
- For nondrilling, the disconnect initiation offset is adjusted by 50 ft before the EDS time. This is the modified red limit for nondrilling.
- For drilling, the disconnect initiation offset is typically 90 sec before EDS.
VIV Analysis
The objectives of performing VIV analysis of the drilling risers are as follows:
- Predict VIV fatigue damage.
- Identify fatigue critical components.
- Determine the required tensions and the allowable current velocity.
Following the modal solution, the results are prepared for input to Shear7 [8]. SHEAR7 is one of the leading modeling tools for the prediction of vortex-induced vibration (VIV) developed by MIT. Parameters that remain user defined are as follows:
- Mode cut-off value;
- Structural damping coefficient;
- Strouhal number;
- Single and multimode reduced velocity double bandwidth;
- Modeling of the straked riser section with VIV suppression devices.
In a VIV analysis of the drilling riser, the vessel is assumed to be in its mean position. The analysis includes these tasks:
- Generate mode shapes and mode curvatures for input to VIV analysis using a finite element modal analysis program.
- Model the riser using Shear7 based on the tension distribution determined from initial static analyses.
- Analyze the VIV response of the riser for each current profile using Shear7.
- Evaluate the damage due to each current profile.
- Plot the results in terms of VIV fatigue damage along the riser length for each current profile.
Wave Fatigue Analysis
A time-domain approach is adopted for motion-induced fatigue assessment of the drilling riser. No mean vessel offsets or low-frequency motions are considered for motion fatigue analysis of the drilling riser. The procedure for performing a fatigue analysis is as follows:
- Perform an initial mean static analysis.
- Apply relevant fatigue currents statically as a restart analysis.
- Perform dynamic time-domain analyses for the full set of load cases, applying the relevant wave data for each analysis.
- Postprocess the results from the time-domain analyses to estimate fatigue damage of the drilling riser at the critical locations.
Hang-Off Analysis
Two hang-off configurations are assumed as follows: a hard hang-off in which the telescopic joint is collapsed and locked, thereby forcing the top of the riser to move up and down with the vessel; and a soft hang-off in which the riser is supported by the riser tensioners with all air pressure vessels (APVs) open and a crown-mounted compensator (CMC), providing a soft vertical spring connection to the vessel. Time-domain analysis is conducted using random wave analysis and a simulation time of at least 3 hr. The hard hang-off cases are the 1-year winter storm (WS), 10-year WS, and 10-year hurricane. The soft hang-off cases are the 10-year WS and the 10-year hurricane. The goal of the timedomain dynamic analysis is to investigate the feasibility of each mode. In a hang-off configuration model, the riser is disconnected from the BOP, and only the LMRP is on the riser. For the hard hang-off method, only the displacements are fixed. The rotations are determined by the stiffness of the gimbal-spider. The trip saver is at the main deck. For the soft hang-off method, the riser weight is shared equally by the tensioner and the draw works. The draw works have zero stiffness. The tensioner stiffness may be estimated based on the weight of the riser supported by the tensioners and the riser stroking from wave action. The evaluation criteria for soft and hard hang-off analyses are as follows:
- For soft hang-off, use the stroking limit for the tensioner and slip joint;
- Minimum top tension to remain positive to avoid uplift on the spider;
- Maximum top tension: rating of substructure and the hang-off tool;
- Riser stress limited to 0.67 Fy;
- Gimbal angle to prevent stroke-out;
- Maximum riser angle between gimbal and keel to avoid clashing with the vessel.
Dual Operation Interference Analysis
Dual operation interference analysis evaluates the different scenarios proposed for having the drilling riser in place and connected on the main rig while performing deployment activities on the auxiliary rig. The goal of this analysis is to identify limiting currents and offsets where these activities can take place without causing any clashing between the drilling riser, the suspended equipment on the auxiliary rig, or the winch. The distance between the main riser and the auxiliary rig and between the main rig and winch is an important design parameter. Note that clashing of the main riser with the moon-pool, vessel hull, or bracing will need to be assessed separately prior to finalizing the stack-up model. A static offset will be applied according to supplied information on the dual operation activity and subsequently another static offset of the vessel due to current loading. Finally, the current loading will be added and then the system will be evaluated for minimum distance between the drilling riser, the dual operation equipment, and the vessel. A drag amplification factor will be applied to the completion riser (off of the auxiliary rig) to account for VIV drag. No drag amplification will be added to the drilling riser (off of the main rig) to conservatively estimate its downstream offset due to the current. The auxiliary rig equipment will be considered deployed at 10, 30, 60, and 90% of water depth and upstream, whereas the main drilling riser will always be onsidered to be downstream and connected.
Contact Wear Analysis
The contact between the drill string and the bore of the subsea equipment may result in wearing of both surfaces due to the rotation and running/ pulling of the drill string. The softer bore of the subsea equipment will experience more wear than the drill string and, therefore, it is the subject of this section. The wear volume estimation is based on the work of Archard [9] and others. The expression for wear is given by: Vwt ¼ ðK=HÞN S (25-1) where Vwt: total wear volume from both surfaces, in.3; K: material constant; H: material hardness in BHN; N: contact force normal to the surfaces, lbf; S: sliding distance, in.. This result is based on several hundred experiments that included a wide range of material combinations. The experimental result demonstrates that the wear rate, Vw/S, is independent of the contact area and the rate of rotation or sliding speed, as long as the surface conditions do not change. Such a change can be caused by an appreciable rise in surface temperature. The H value for 80-ksi material is 197 BHN. For the flexjoint wear ring and wear sleeve, H is 176 BHN. The normal force, N, is obtained from the contact analysis of the drill string for the load cases. The sliding distance, S, is related to the string RPM as follows: S ¼ p dðRPMÞ t (25-2) where d is the diameter of the drill pipe/tool joint, and t is the time in minutes. Substitution of Equation (25-1) into Equation (25-2) and solving for t as a function of Vw gives: t ¼ ðH=KÞ ðVw=NÞ ðp dRPMÞ (25-3) The drilling fluid provides lubrication with reduction in wear by comparison to the dry contact conditions. Therefore, the results of this study, which are based on unlubricated wear, will be conservative. The wear volume, Vw, can be further related to the wear thickness, tw, by the wear geometry as discussed in the next section. Because the goal is to find the wear thickness, the wear geometry should be considered. The wear area is the crescent bounded by the bore and the OD of the tool joint or the drill pipe. The following are the possible contact cases:
- Tool joint contact with casing;
- Tool joint contact with BOP-LMRP;
- Tool joint contact with riser joint;
- Tool joint contact with flexjoint;
- Drill pipe contact with riser joint;
- Drill pipe contact with flexjoint.
For each tension, and each position of the tool joint, the flexjoint angle is increased between 0 and 4 degrees at increments of 0.1 degree. The reaction forces at each increment are reported. As long as the drill string tension is maintained at a given angle that is greater than zero, the wear process will continue under the reaction forces. Because of the large scale of the problem, these reaction forces remain unchanged for wear thicknesses of up to 1 in. So the question becomes this: How much time does it take to wear out a certain thickness? The first step in calculating wear is to estimate the drill string tension near the mudline since the contact reaction forces depend on this tension. To simplify the wear alculations, a conservative approach is implemented where the reaction forces for each contact location are normalized with respect to the drill string tension for the five positions of the tool joint. A typical wear calculation procedure could be as follows:
1. Determine as input the following:
- Angle of drilling;
- Material Brinell hardness;
- Tension range;
- RPM.
2. Calculate the normal force from the reaction envelopes from the tension. 3. Obtain the sliding distance, S, from the tw Vw values. 4. Obtain the time, t, in minutes for each tw.
Recoil Analysis
The objectives of conducting a recoil analysis are to determine recoil system settings and vessel position requirements, which ensure that during disconnect the following are achieved: 1. The LMRP connector does not snag. 2. The LMRP risers clear the BOP. 3. The riser rises in a controlled manner.
Recoil analysis is not required for every specific application if the vessel has an automatic recoil system. The criteria to be considered at each stage of recoil are as follows:
- Disconnect: The angle of the LMRP as it leaves the BOP should not exceed the allowable departure angle of the connector. This may limit the possibility of reducing tension prior to disconnect.
- Clearance: The LMRP should rise quickly enough to avoid clashing with the BOP as the vessel heaves downward.
- Speed: The riser should not rise so fast that the slip joint reaches maximum stroke at high speed.
Requirements for modeling the riser during recoil are the same as those needed for hang-off. In addition, it must be possible to account for the nonlinear and velocity-dependent characteristics of the tensioner system. A time-domain riser analysis program can be used alone or in conjunction with spreadsheet calculations from which tensioner characteristics are derived. The analysis sequence is as follows:
- Conduct analysis of the connect riser.
- Release the base of the LMRP, to reflect unlatching, and analyze the subsequent response for a short period of time.
- Change tensioner response characteristics to simulate valve opening or closure and analyze subsequent riser response for a number of wave cycles. The analysis is repeated to determine the necessary time delay between operations. The upstroke of the riser must be monitored to detect whether top-out occurs and at what speed. If the riser is to be allowed to stroke on the slip-joint during hang-off, vertical oscillation of the riser following disconnect must also be monitored to ensure that clashing with the BOP does not occur.
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