25.2.1 Completion and Workover (C/WO) Risers

Two different types of risers are used for installation and intervention in and on a well: completion risers and workover risers.

A completion riser is generally used to run the tubing hanger and tubing through the drilling riser and BOP into the wellbore. The completion riser may also be used to run the subsea tree. The completion riser is exposed to external loading such as curvature of the drilling riser, especially at the upper and lower joints.

A workover riser is typically used in place of a drilling riser to reenter the well through the subsea tree, and may also be used to install the subsea tree. The workover riser is exposed to ocean environmental loads such as hydrodynamic loads from waves and currents in addition to vessel motions.

Figure 25-2 is a typical figure for a C/WO riser, taken from ISO code for Completion and Work Riser Systems[2]. The C/WO riser can be a common system with items added or removed to suit the task being performed. Either type of risers provides communication between the wellbore and the surface equipment. Both resist external loads and pressure loads and accommodate wireline tools for necessary operations.

Figure 25-2 Stack-Up Model for a C/WO Riser

[2]

Riser connectors are one of the most important riser components. As drilling depths have increased, riser connectors have evolved to address issues concerning high internal and external pressures, increasing applied bending moment and tension loads, and extreme operating conditions such as sweet and sour services. For connector design, the material selection and fabrication of bolts are critical issues.

Figure 25-3 shows key components in a typical drilling riser system. Figure 25-4 shows bolt-based riser connectors.

Figure 25-3 Key Components in a Drilling Riser System

(Courtesy of World Oil[1])

Figure 25-4 Riser Connector

(Courtesy of World Oil[1])

The spider is a device with retractable jaws or dogs used to hold and support the riser on the uppermost connector support shoulder during running of the riser. The spider usually sits in the rotary table on the drill floor.

The gimbal is installed between the spider and the rotary table. It is used to reduce shock and to evenly distribute loads caused by a rig’s roll/pitch motions, on the spider as well as the riser sections.

A slick joint, also known as a telescope joint, consists of two concentric pipes that telescope together. It is a special riser joint designed to prevent damage to the riser and control umbilicals where they pass through the rotary table. Furthermore, it protects the riser from damage due to rig heave.

Riser joints are the main members that make up the riser. The joints consist of a tubular midsection with riser connectors in the ends. Riser joints are typically provided in 9.14- to 15.24-m (30- to 50-ft) lengths. For the sake of operating efficiency, riser joints may be 75 ft in length. Shorter joints, called pup joints, may also be provided to ensure proper space-out while running the subsea tree, tubing hanger, or during workover operations.

Depending on configuration and design, a drilling riser system also consists of the following components:

25.2.2 Diverter and Motion-Compensating Equipment

A diverter is similar to a low-pressure BOP. When either gas or other fluids from shallow gas zones enter the hole under pressure, the diverter is closed around the drill pipe or kelly and the flow is diverted away from the rig.

All floating drilling units have motion-compensating equipment (as shown in Figure 25-5) installed to compensate for the heave of the rig. Compensators function as the flexible link between the force of the ocean and the rig. The equipment consists of the drill string compensator, riser tensioners, and guideline and podline tensioners. The drilling string compensator, located between the traveling block and swivel and kelly, permits the driller to maintain constant weight on the bit as the rig heaves. Riser tensioners are connected to the outer barrel of the slip joint with wire ropes. These tensioners support the riser, and the mud within it, with a constant tension as the rig heaves. The guideline and podline maintain constant tension on guideline wire ropes, and wire ropes that support the BOP control podlines as the rig heaves.

Figure 25-5 Motion-Compensating Equipment

(Courtesy of World Oil[1])

25.2.3 Choke and Kill Lines and Drill String

Choke and kill lines are attached to the outside of the main riser pipe (see Figure 25-6). They are used to control high-pressure events. Both lines are usually rated for 15 ksi. High pressure is circulated out of the wellbore through the choke and killed lines by pumping heavier mud into the hole. Once the pressure is normal, the BOP is opened and drilling resumes. If the pressure cannot be controlled with the heavier mud, cement is pumped down the kill line and the well is killed.

Figure 25-6 Complete Riser Joint

(Courtesy of Offshore Magazine, May 2001[3])

The drill string permits the circulation of drilling fluid or liquid mud. Some functions of this mud are to:

25.3.1 Subsea Wellhead Systems

The foundation of any subsea well is the subsea wellhead. The function of the subsea wellhead system is to support and seal the casing string in addition to supporting a BOP stack during drilling and also the subsea tree under normal operation.

Installation of equipment to the seabed is generally done by one of two methods:

Regardless of the guidance system, the procedure in which the wellhead system is installed is as follows:

25.3.2 BOP

The marine riser is used as a conduit to return the drilling fluids and cuttings back to the rig and to guide the drill and casing strings and other tools into the hole. Geiger and Norton [4] have provided a short and relevant description on floating drilling.

The well is begun by setting the first casing string known as the conductor or structural casing—a large-diameter, heavy-walled pipe—to a depth that is dependent on soil conditions and strength/fatigue design requirements. Its primary functions are to:

The depth and size of each drilling string is determined by the geologist and drilling engineer before drilling begins. When drilling from a semisubmersible or drill ship, the wellhead and BOP must be located on the seabed.

The BOP stack is used to contain abnormal pressures in the wellbore while drilling the well. The primary function of the BOP stack is to preserve the fluid column or to confine well fluids or gas to the borehole until an effective fluid column can be restored.

At the lower end of the riser is the lower flexjoint. After the hole has been drilled to its final depth, electric logs are run to determine the probable producing zones. Once it has been determined that sufficient quantities of oil and gas exist, the production tubing is then run to the zone determined to contain that oil or gas. Only after this takes place is the well “completed” by removing the BOP stack and installing the fittings used to control the flow of oil and gas from the wellhead to the processing facility.

25.3.3 Tree and Tubing Hanger System

To complete the well for production a tubing string is installed in and supported by a tubing hanger. The tubing hanger system carries the tubing and seals of the annulus between casing and tubing. To regulate flow through the tubing and annulus, a subsea tree is installed on the wellhead. The subsea tree is an arrangement of remotely operated valves, which controls the flow direction, amount, and interruption.

25.4.1 Operability Limits

Table 25-1 presents the typical criteria used for determination of the operability limits for the drilling riser, defined mainly based on API 16Q [5].

Table 25-1. Criteria for Drilling Riser Operability Limits

In general, a DNV F2 curve is used for the weld joints and a DNV B curve for the riser connectors (coupling). Two stress concentration factors (SCFs) are used in fatigue analysis, one is 1.2 for the girth welds, and the other is roughly 2.0 for riser connectors, depending on the type of risers. In recent years, fatigue qualification testing has been performed to determine the actual S-N curve data. An engineering criticality assessment (ECA) analysis is conducted to derive defect acceptance criteria for inspection.

For the drilling riser, the safety factor on fatigue life is 3 because the drilling joints can be inspected. The fatigue calculations are to account for all relevant load effects, including wave, VIV, and installation-induced fatigue. In some parts, such as the first joints nearest the lower flexjoint (LFJ), the fatigue life could be less, in which case the fatigue life will determine the inspection interval.

25.4.2 Component Capacities

For strength checks, various component capacities need to be defined such as:

25.5.1 Drilling Riser Stack-Up Model

A schematic of a typical drilling riser stack-up was shown earlier in Figure 25-2. The weight in air and seawater for the telescopic joint, flexjoints, LMRP, and BOP need to be defined for riser analysis.

The submerged weight and dimensions (length × width × height) for the production trees, manifolds, and jumpers are required for the dual activity interference analysis. The properties of the auxiliary rig drill pipe and wire rope will also be used in the interference analysis.

The recommended tensioner forces used in the analysis are calculated based on the mud weight. In the analysis, the drilling mud densities are typically assumed to be 8.0, 12.0, 16.0 ppg, etc. The maximum allowable bending moment in the casing may be determined assuming the allowable stress is 80% of yield strength.

The hydrodynamic coefficients to be used in the analysis include the normal drag coefficient and the associated drag diameters for the bare and buoyancy joints. The tangential drag coefficient may be taken from API RP 2RD [6], Section 6.3.4.1, Equation 31. For the LMRP and the BOP, the vertical and horizontal drag areas and coefficients may be provided by suppliers.

The red alarm is typically 60 sec before disconnect point, and the yellow alarm is roughly 90 sec before the red alarm.

25.5.2 Vessel Motion Data

The required vessel motion data include the following:

In addition, wave drift force quadratic transfer functions for surge, sway, and yaw are required to conduct irregular wave force calculations in a drift-off analysis. Wind and current drag coefficients for the vessel are also required.

25.5.3 Environmental Conditions

Generally angles denote the direction “from which” the element is coming, and they are specified as clockwise from true north.

Tidal variations will have a negligible effect on the loads acting on deepwater risers and may be negligible in the design.

Environmental conditions include:

Background current is the current that exists in the upper portion of the water column when there is no eddy present. Mean values of the soil undrained shear strength data, submerged unit weight profile, and ε₅₀ profiles are used along the soil column to calculate the equivalent stiffness of the soil springs, for analysis of the connected riser.

25.5.4 Cyclic p-y Curves for Soil

The methodology for deriving a p-y curve for soft clay for cyclic loading was developed by Matlock [7]. A family of p-y curves will be required to model the conductor casing/soil interaction at various depths below the mudline.

25.6.1 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.

25.6.2 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 [5].

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 H_max, 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:

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:

Limitations may also arise from loading on the wellhead and conductor system:

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.

25.6.3 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 manufacturers’ specifications. The areas of potential weakness in a drilling riser system are typically:

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:

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.

25.6.4 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:

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:

25.6.5 VIV Analysis

The objectives of performing VIV analysis of the drilling risers are as follows:

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:

In a VIV analysis of the drilling riser, the vessel is assumed to be in its mean position. The analysis includes these tasks:

25.6.6 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:

25.6.7 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 time-domain 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:

25.6.8 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 considered to be downstream and connected.

25.6.9 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:

(25-1)

where

This result is based on several hundred experiments that included a wide range of material combinations. The experimental result demonstrates that the wear rate, V_w /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:

(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 V_w gives:

(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, V_w , can be further related to the wear thickness, t_w , 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:

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 calculations, 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:

25.6.10 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:

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:

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:

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.