OTC 15385

Horn Mountain Spar Risers – Evaluation of Tension and Installation Requirements for Deepwater Dry Tree Risers E.J. O’Sullivan, MCS; R.B. Shilling, BP; A.D. Connaire, F.W.A. Smith, MCS

Copyright 2003, Offshore Technology Conference This paper was prepared for presentation at the 2003 Offshore Technology Conference held in Houston, Texas, U.S.A., 5–8 May 2003. This paper was selected for presentation by an OTC Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Offshore Technology Conference and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Offshore Technology Conference or its officers. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Offshore Technology Conference is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of where and by whom the paper was presented.

Abstract The development of dry-tree vessel technology and the installation of several Spar systems in increasingly deep water in the Gulf of Mexico has led to the parallel evolution of several designs of dry-tree risers, most of which rely on air cans to provide top tension. These risers typically consist of multiple concentric pipes, with production risers configured as production tubing within a single or dual casing steel riser construction. The tension applied to the top of each pipe must be enough to prevent damage through buckling of either the riser or tubing under all installation, operation and workover conditions, while still providing a margin of safety various damaged conditions. The sum of these tensions determine the capacity of the tensioning system required for all relevant loading conditions, without overstressing the riser or tubing in design sea states.

To evaluate the tension requirements and the distribution of tension between constituent pipes, a rational approach has been developed and successfully applied to BP’s Horn Mountain Spar dual casing riser system, which at 5,423ft represents the deepest Spar riser system to date. The approach uses finite element multi-tube analysis to determine the relative elongation and load sharing between the tubing, inner riser and outer riser under all load conditions. Riser and tubing elongation, internal fluid effects, seawater & riser temperature distributions under installation and operating conditions are all considered as part of this approach. This approach implicitly considers the 3-D riser and wellbay geometry and the wellhead elevation at each of the subsea well locations.

As part of installation planning, this approach has been used to confirm the air can tensioning system capacity, chamber size and redundancy requirements; predict air can elevations and buoyancy requirements at each stage of riser installation; and establish riser and tubing tensions along with

relative stretch requirements to land each string in the surface wellhead system to ensure the appropriate in-service distributions of tensions for all service conditions. Horn Mountain Spar The Horn Mountain field is located 84 miles from Venice, Louisiana offshore in Mississippi Canyon Block 126 and 127 in a water depth of 5,423ft. This represents the deepest dry tree production riser installation to-date. Leases for these blocks are held 67% by BP, and the remaining 33% by OXY USA, Inc. with BP as the Operator.

The Horn Mountain field is being developed with a Truss Spar production facility. The 106ft x 555ft Truss Spar accommodates a temporary completion rig that has robust sidetrack and workover capabilities, and lightweight production facilities that allow for 4,700ton single piece deck lift. A schematic and picture of the Spar are shown in Figure 1. The wellbay, which is 52ft x 52ft in overall dimension, is in a 4 x 4 type configuration and accommodates 14 production top tensioned riser (TTR) slots and 2 import steel catenary riser (SCR) well slots. The seafloor layout was optimized for pullover drilling as a mirror image of the wellbay with 50ft between adjacent wells as indicated in Figure 2.

The initial 10 wells [8 production and 2 water injection] were predrilled using a moored semi-submersible, prior to the Spar arriving on location and are batch completed using the Spar completion rig. Each TTR is a weight optimized dual barrier configuration with a 12¾” outer riser, a 95/8” inner riser and a 4½” tubing. Tension for each riser is provided by a non-integral 230 ft long by 12ft diameter air can. The Spar and riser system is configured to be pulled over approximately 325ft to allow the four remaining wells to be drilled from a dynamically positioned DP3 semi-submersible. Subsea wells can be accommodated using the SCR wellbay slots. The export 12” oil and 10” gas SCRs are hung using flex joints from a porch at the base of the Spar hard tank and routed in an external blister to the deck. Horn Mountain Riser System and Tensioning System A schematic of the production riser stack-up and of the riser/air can configuration within the wellbay is shown in Figure 3. The dimensions of each riser are as follows: Outer riser – 12¾” OD x 0.440” WT Inner riser – 95/8” OD x 0.435” WT Production Tubing – 4½” OD x 12.6 lb/ft

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The non-integral air can system consisted of 4 major components: a lower stem, b air can, c upper stem, and d upper stem head with a work platform.

The concentric stem joints surrounds each riser string and act as a conduit through the Spar from the surface wellhead to the keel. The upper stem of dimensions 36” OD, ¾” WT and 87ft in length, supports the surface wellhead of each riser. The lower stem of dimensions 36” OD, ½”-1½” WT and 292ft in length extends through the keel.

Each air can has a total of 12 buoyancy chambers, plus the stem. The top four air can chambers are sealed and provide buoyancy to offset the can weight. The bottom 8 chambers are filled with air during the installation process and produce about 125kips net each. The internal stem is aired prior to workover and is designed to produce the equivalent of one additional chamber when 70% full. The stem, however, can be fully evacuated and provide a total of nearly 200kips additional buoyancy, if required.

Each air can is capable of providing a net buoyancy force of 1,200kips, which includes 200kips available from airing the stem. In the neutral position after riser installation, the top of each air can is designed to be at 5ft above the mean water line (MWL). The maximum allowable upstroke and downstroke for each riser is 15ft and 25ft, respectively. Air Can System Design Horn Mountain air can system design boasts several innovative firsts including: A light weight single piece construction for buoyant

efficiency, Dual chamber redundancy, Compliant guides at the top and bottom of the cans to

cushion impact with the hull, Extended fiberglass vent tubes from each chamber to

increase air can efficiency during downstroke, and Several installation aids including auto aligning squnch

joint connections for the upper and lower stem and a passive alignment system to rotate the air cans while being lowered to align wear strips with the guides in the hull.

The air can system installation sequence is shown in Figures 4 thru 10. All ten systems were installed without incident in little more than 5 days, which significantly improved safety and greatly reduced risk and overall cost.

The single piece air can construction is weight optimized, along with the riser system, to provide dual chamber redundancy. Dual chamber redundancy is desired because of the difficulty in removing and repairing a damaged large single piece can. Dual chamber redundancy means that even if one chamber per air is lost, the system still maintains a single extra chamber of buoyancy to satisfy top tension requirements for all service life load conditions. Fiberglass vent tubes extend from the bottom of each chamber approximately 17ft down through the adjacent lower chamber and out the air can. When the chambers are filled, they are blown dry all the way through the vent tubes. This provides three distinct advantages: a The air water interface is maintained in the fiberglass

section providing superior corrosion protection,

b The air water interface area is minimized reducing the absorption rate and subsequent need to “top off” the cans, and

c The tubes increase the efficiency of the system by keeping water out of the chamber in all but the most severe downstroke conditions as seen in Figure 11.

Horn Mountain is the first Spar to design and use compliant guides to improve fatigue life of the air can system. The compliant guides, presented in Figure 12, eliminate any gap between the air can and hull, minimizing the large slamming impact loads with the hull seen in earlier Spars. Without the guides, gaps of 1” or greater are required in order to install the cans within manufacturing tolerances of the system. With gaps as small as 1”, impact loads five times larger than quasi-static loads have been seen in model tests and full-scale measurements. Compliant guides eliminate these impact loads and significantly increase air can and hull fatigue life as presented in Figure 13. Note, the compliant guides impart a friction load to the air can. This friction load always acts as a restraint on the air can vertical movement and is approximately 25kips in magnitude. This friction load is accounted for in developing the riser installation procedure, presented later in this paper. Dual Casing Riser Tension Factor Selection The air can tensioning system must be capable of providing adequate tension to the riser for a range of riser operating conditions including normal production, workover, completion, well killed and shut in. Based on the possible permutations of internal fluids and functional loading of the riser assembly that can occur in the riser for such operating conditions, a matrix comprising 13 of those considered most critical were identified. These 13 cases form the basis for the evaluation of the tension factor design and tension distributions within the riser. Note that for this paper, top tension factor is the ratio of the applied top tension to apparent weight of the entire riser assembly.

The design load cases matrix for the 13 critical cases are as shown in Table 1. The top tension factors applicable for each load case under the two extreme redundancy scenarios are shown in Table 2. Notably a top tension factor of approximately 1.6 is available for normal production conditions. Furthermore, the precise load contribution from each air can is critical and closely monitored during installation to ensure that appropriate pre-stretch and slack off conditions prevail during latching. Requirements for Inner Riser Pre-Stretch and Tubing Slack Off In order to ensure acceptable base tensions of the outer riser, inner risers and tubing, over the full field life, the following quantities are critical requirements for riser installation: Pre-stretch [overpull] of the 9-5/8” inner riser Slack off of the 4-½” tubing at the packer

The evaluation of these parameters is vital in ensuring that the forces at the base of the risers and tubing are within acceptable levels for the critical load cases outlined in Table 1. Specifically, under all conditions, except for critical survival conditions, there is a requirement to maintain tension at the base of the inner riser and also at the seabed elevation of the tubing. Effects that must be considered in evaluating these

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quantities are internal fluid density, pressure, Poisson's effect and temperature. Particularly, it was found that during late field life period, a combination of high water cut profile, high flowing temperature and gas lift in the inner annulus [Case 1, Table 1] causes compression in the inner riser due to expansion of the production tubing under high temperature loading. The controlling temperature profile data for this case is shown in Figure 14. This represents 50% water cut, with 5,500BOPD late in field life. This and all other loading critical conditions are analyzed using equivalent riser assembly finite element models using Flexcom-3D, [1], to predict tension distributions. Finite Element Modeling and Analysis Finite element models the riser system are developed using Flexcom-3D. The inner and outer riser casings are modeled to the seabed, while the production tubing is modeled to the total depth.

The loading effects incorporated into these models for the load cases are as follows. Poisson effects on the: Tubing due to: applied internal pressure internal pressure head due to fluid in the tubing applied external pressure in inner annulus external pressure head due to fluid in inner annulus external pressure head due to mud outside tubing from

6,000ft below mudline to packer Inner riser due to: applied internal pressure internal pressure head due to fluid in inner riser applied external pressure in outer annulus external pressure head due to fluid in outer annulus Outer riser due to: applied internal pressure internal pressure head due to fluid in outer riser external pressure head due to seawater

End cap effect on: Annular area only due to applied pressure in tubing, Annular area only due to applied pressure in inner annulus, and Annular area only due to applied pressure in outer annulus.

Temperature differentials in each riser/tubing as referenced to the undisturbed temperature profile. All appropriate buoyancy effects, taking into account each

annular fluid, and including buoyancy effects on the tubing in mud below the mudline.

The vertical tension, which is provided by the air can assembly, is applied to the uppermost node of the model. The uppermost node is equivalent for the risers and tubing. Equivalent elongations are calculated, which incorporate the loading affects and applied as vertical boundary conditions to the lowermost nodes of the inner tubing and riser. Static equilibrium analyses are performed to establish the equivalent elongation of the riser assembly and the resulting tension distributions. Analysis Results and Tensioning Distributions The static equilibrium analyses for all 13 load cases (Table 1) are performed for a range of permutations of inner riser pre-

stretch values and tubing slack off values at installation. It is found that in order to meet the requirement of positive tension in the inner riser during the late life production load case [Case1, Table 1] a pre-stretch of 22” is required on the inner riser during riser installation. Furthermore it is established that a slack off of 10kips at installation to land the tubing head in the surface hanger on board the Spar is required once the tubing has been run and the downhole packer set.

The corresponding tension distribution under these conditions of pre-stretch and slack off, are outlined in Table 3. The top and base tensions in the outer riser, inner riser and tubing for each load case are shown in Figures 16 and 15. The base tension, which is the critical parameter to consider is shown to be within allowable limits in all cases for the inner riser, with the notable exception being for Case 10. This case, whereby inner riser and tubing leaks with an internal pressure of 5,500psi in both annuli, is considered a survival case with very low probability of occurrence. Hence, the level of compression seen in the inner riser is not considered sufficient to cause system failure and is therefore acceptable.

Some other key results from Table 3, which improve the understanding of the multi-pipe system, are as now discussed: Case 1: The minimum tension in the tubing is caused mainly

by lack of buoyancy from the gas in the inner riser. Case 5: The buoyancy loads are largest for the inner riser

with nitrogen in the inner riser and 3.5ppg in the tubing. This leads to a maximum top tension case for the inner riser.

Case 10: The high pressure induces a hoop load on the outer riser. The associated Poisson’s effect tends to induce a negative elongation. This reduces tension from the inner riser.

Case 13: The minimum tension occurs in the outer riser. Case 13 is the heaviest with the BOP connected, treated seawater and mud in the risers and tubing for completion conditions. As the outer riser is the stiffest member, it carries the most load.

In order to demonstrate the importance of maintaining tight tolerances during installation, particularly during inner riser pre-stretch, the effects of a variation of ±3½” in the recommended value of 22” for the critical condition [Case 1, Table 1] are shown in Table 4. Under these conditions, tensions are within the allowable levels with 6.1kips reported for the inner riser for a pre-stretch of 18½”. Required Installation Mechanism and Procedure To ensure the appropriate in-service distribution of tension between outer and inner riser casing and production tubing, the meticulous planning and execution of an installation sequence of the riser system is vital. Many analyses were performed using the models and accounting for the effects described in Finite Element Modeling and Analysis section earlier. The importance of the careful planning of each stage lies in the necessity to have adequate tension provided by either a combination of air-can, completion rig and friction effects of air-can compliant guides while ensuring appropriate relative elongation between each riser and tubing.

Further to these requirements, it is noted that with each step the relative contribution of each of these effects will alter. For example when the hook load is removed from the inner riser after the inner riser is connected to the outer riser, the air

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cans and friction loads from the air-can guides will be forced to support the inner riser. This in turn would cause the elongation of the entire assembly to reduce, the cans to drop and hence the air can load to increase due to increased pressure. Such complex interaction will affect the relative elongation between inner and outer riser [and between tubing and inner riser], which we have we have seen from Analysis Results and Tensioning Distributions section earlier to be such important quantities.

For each stage of installation the following quantities must be accurately predicted at design stage and carefully monitored during installation: Top tensions in outer riser, inner riser and tubing Tensions at seabed in outer riser, inner riser and tubing Tension in tubing at packer Load being provided by the rig to riser or tubing Air can load being applied to riser assembly Friction load and direction of action

Once these quantities are known prior to a given installation stage, the amount by which they will alter during the stage are calculated. The installation sequence is followed stage-by-stage within the constraint of the underpinning limitations until the installation is complete and relative elongations between each riser exist.

Specifically, for the Horn Mountain installation, 43 stages define the installation sequence for each riser. Much of the earlier stages are concerned with the installation of the outer riser and initial transfer of outer riser load to the air cans. This aspect of the installation is not dealt with in this paper. The stages of most interest in the context of this paper are those in which elongation in applied to inner riser [and tubing] and the load transfer occurs from the rig to air can assembly. Specifically Stage 30 to Stage 41 are described below. For critical stages, summary figures illustrate the process. Stage 30: The inner riser is latched into the subsea wellhead

with the internal tieback tool, and using the rig a tension is applied at the top end until such a time that the inner riser experiences an elongation of 22”, (Figure 17a)

Stage 31: The riser is then subjected to an additional elongation of 13¼” to facilitate the landing of the adjustable surface wellhead hanger with the appropriate support ring. The support ring is put in place.

Stage 32: The additional elongation is now reduced and the inner riser moves downwards until the support ring landed in the surface wellhead system. Both the inner and outer risers are now latched together.

Stage 33: The cans are then aired and contribute some tension to the inner riser via the hanger support ring. The rig hook load is however maintained during this stage, (Figure 17b).

Stage 34: The hook load is slowly removed and the air cans now become the primary source of tension on the riser, (Figure 17c).

Stage 35: The air can buoyancy is increased to 1050kips in preparation for completion.

Stage 36: The BOP and telescopic joint are added. Stage 37: Seawater is displaced with completion fluid in inner

riser. The well is now ready for completion.

Stage 38: The tubing is run through the inner riser and spaced out to set the down-hole packer.

Stage 39: The down-hole packer is set and a slack off of 10kips is applied to the tubing at packer to land tubing head in surface hanger. The hanger should now be locked down, (Figure 17d).

Stage 40: The hook-load off the tubing is relieved, (Figure 17e).

Stage 41: The BOP is removed and x-mas tree added. Control lines are terminated.

Figure 18 presents the tension variations and load distributions for risers, tubing, air cans and hook for the sequence of stages. In all cases the air can and hook combination is sufficient to provide the tension required to give the correct distribution in risers, which in turn are compatible with the relative elongations necessary for acceptable tensions for a range of in-service conditions.

This procedure has been successfully applied to the Horn Mountain dry tree riser system. The installation occurred in the autumn of 2002 with first oil achieved in November 2002. Conclusions A rational approach is presented for evaluating the riser and tubing tensions for any dry tree multi-tube riser system. This finite element analysis methodology, which considers actual 3-D riser geometry, avoids simplifications capable of leading to inaccuracy with simpler approaches. Multiple pressure, temperature and axial loading effects are incorporated in the static equilibrium analysis of the multi-tube model.

This approach is applied to the Horn Mountain Spar dry tree riser system, which incorporates innovative efficient air cans with dual chamber redundancy, single piece construction with compliant guides to cushion impact with the hull. Extended fiberglass vent tubes from each chamber increase air can efficiency during downstroke. The air cans are capable of providing adequate tension to the risers for a range of riser operating conditions including normal production, workover, completion, well killed and shut in.

Relative elongations between risers and tubing are calculated for the installation sequence, to ensure that individual pipe compression does not occur at or above the mudline. To meet this requirement in late life production, a pre-stretch of 22”, with a tolerance of ±3½” is required on the inner riser during riser installation. In addition a slack off of 10kips when landing the tubing head in the surface hanger on board the Spar is required once the downhole packer has been set.

The detailed riser and tubing installation procedure has been successfully used on Horn Mountain, with first oil achieved in November 2002.

Acknowledgements The authors would like to acknowledge Metin Karayaka, Alan Cordy and Wade Mallard of Technip-Coflexip, who were involved in the air can and compliant guide system development, for the air can and compliant guide system specific details and selected figures included in this paper. References 1. Flexcom-3D, Three Dimensional Nonlinear Time Domain

Offshore Analysis Software, MCS International, Galway, Ireland.

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Table 1 Load Case Matrix

Outer Riser Inner Riser Tubing Case Load Case Density

(ppg) Pressure

(psi) Density

(ppg) Pressure

(psi) Density

(ppg) Pressure

(psi)

Top Tension

(kips)

BOP Temp. Profile

1 Producing 9.00 200 2.00 1,900 7.00 2,250 960 No Hot 2 Well Killed 9.00 200 10.80 200 10.80 0 1,050 No Cold 3 Well Killed – N2 9.00 200 0.02 200 10.80 0 960 No Cold 4 Max Shut In with Kill Fluid 9.00 220 10.80 220 3.50 5,500 1,050 No Cold 5 Max Shut In with N2 9.00 220 0.02 220 3.50 5,500 960 No Cold 6 Max Shut In – Surface

Tubing Leak 9.00 200 10.80 5,500 3.50 5,500 1,050 No Cold

7 Shut In – Inner Riser Gas Lift Leak

9.00 1,900 2.00 1,900 7.00 2,250 960 No Cold

8 Shut In – External Riser Evacuation

0.02 0 0.02 0 7.00 2,250 960 No Cold

9 Shut In – Internal Riser Evacuation

9.00 200 0.02 0 7.00 2,250 960 No Cold

10 Surface Inner Riser & Tubing Leaks

9.00 5,500 10.80 5,500 3.50 5,500 1,050 No Cold

11 Workover Through 9-5/8” 9.00 200 10.80 0 N/A N/A 1,050 Yes Cold 12 Workover – Shut In Well

Control 9.00 200 10.80 2,250 N/A N/A 1,050 Yes Cold

13 Completion 9.00 200 10.80 0 10.80 0 1,050 Yes Cold Table 2 Top Tension Factors

Case Load Case Intact 2 Chambers Damaged 1 Producing 1.49 1.23 2 Well Killed 1.42 1.04 3 Well Killed – N2 1.52 1.26 4 Max Shut In with Kill Fluid 1.46 1.08 5 Max Shut In with N2 1.58 1.31 6 Max Shut In – Surface Tubing Leak 1.46 1.08 7 Shut In – Inner Riser Gas Lift Leak 1.49 1.23 8 Shut In – External Riser Evacuation 1.87 1.58 9 Shut In – Internal Riser Evacuation 1.55 1.28 10 Surface Inner Riser & Tubing Leaks 1.46 1.08 11 Workover Through 9-5/8” 1.47 1.04 12 Workover – Shut In Well Control 1.47 1.04 13 Completion 1.32 0.94

Note: Factors were calculated with 6.5% weight penalty margins, actual tension factors are higher. Table 3 Tension Distribution Results for Critical Pre-stretch and Slack Off Loading Conditions

Tension at Top (kips)

Tension at Mudline (kips)

Tension at Packer (kips)

Apparent Weight (kips)

Case

Outer Inner Tube Outer Inner Tube Outer Inner Tube Outer Inner Tube 1 724 116 93 331 18 4 N/A N/A -92 393 98 185 2 549 285 187 157 35 124 N/A N/A 7 393 250 180 3 538 222 173 146 158 61 N/A N/A -60 393 64 233 4 576 305 141 184 55 103 N/A N/A 34 393 250 107 5 616 277 130 223 214 44 N/A N/A -30 393 64 160 6 624 295 103 232 45 65 N/A N/A -4 393 250 107 7 619 172 142 226 74 52 N/A N/A -44 393 98 185 8 469 310 154 371 61 56 N/A N/A -41 98 250 195 9 549 231 153 156 167 55 N/A N/A -42 393 64 195 10 802 116 105 409 -133 67 N/A N/A -2 393 250 107 11 616 336 N/A 224 86 N/A N/A N/A N/A 393 250 N/A 12 650 302 N/A 258 52 N/A N/A N/A N/A 393 250 N/A 13 508 257 187 115 7 122 N/A N/A 6 393 250 181

Table 4 Sensitivity Case Results

Tension at Top (kips)

Tension at Mudline (kips)

Tension at Packer (kips)

Apparent Weight (kips)

Pre-stretch

Outer Inner Tube Outer Inner Tube Outer Inner Tube Outer Inner Tube 25½” 713 128 92 320 29.9 2.9 N/A N/A -93 393 98 185 18½” 734 104 94 342 6.1 4.5 N/A N/A -92 393 98 185

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Figure 1 Horn Mountain SPAR

Figure 2 Horn Mountain Wellbay and Seafloor Layout for Pullover Condition

Figure 3 Horn Mountain Riser and Air Can System

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HEERAMAC BALDER

Single Lift Air Can Air Can Hung Off at Spar Deck

Lower Stem Hung off in Air Can

Figure 4 Air Can Installation Sequence

Lower Stem Installed Upper Stem Installed Air Can Lowered and Installed

Figure 5 Air Can Installation Sequence – continued

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Figure 6 Air Cans with Upper and Lower Stems on Barge

Figure 7 Air Can Lowered thru Alignment funnel to Spar Deck

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Figure 8 Air Cans Hung off at Spar Deck

Figure 9 Lower Stem Lifted, Lowered and Hung off at Spar Deck

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Figure 10 Upper Stem Lifted, Lowered and Squnch Joint Latched

960

980

1000

1020

1040

1060

1080

1100

1120

0 5 10 15 20 25 30

stroke (ft)

Tens

ion

prov

ided

(kip

s)

0

20

40

60

80

100

120

Tens

ion

diffe

renc

e (k

ips)

Current design

New design

Difference between designs

Assume 1100 kips provided by 230 kips air can

Figure 11 Air Can Performance with and without Extended Vent Tubes

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Figure 12 Compliant Guide

MWL=5423ft

Spar Keel (1” gap) 4913ft

Upper Stem Joint

Surface Tree 5518ft

Lower Stem Base 4908.0ft

Air Can Base 5198ft

Air Can Top 5428.0ft

Spar Top 5473.0ft

Hull Guides (1” gap)

Compliant Guides

Spar Deck (0” gap)

Heave plate 1 5013ftHeave plate 2 5091ft

Heave plate 3 5167ft

5250ft

5375.0ft

50 55 60 65 70 75 80 85 90 95 100-400

-300

-200

-100

0

100

200

300

400 Wellbore Temperatures - Gas-Lift above SCSSV

Figure 13 Compliant Guide Configuration and Response Figure 14 Temperature Profiles

30.0 45.0 60.0 75.0 90.0 105.0 120.0 135.0 150.0 165.0 180.0 195.0 210.0 225.0 240.0 255

0

2000

4000

6000

8000

0000

2000

4000

6000

8000

Temperature (deg F)

TVD

(ft)

Tubing FluidTubingTubing AnnuluCasing1Casing1 AnnuCasing2Casing2 AnnuUndisturbed

-200

-100

0

100

200

300

400

500

Outer Casing 331 157 146 184 223 232 226 371 156 409 224 258 115

Inner Casing 18 35 158 55 214 45 74 61 167 -133 86 52 7

Tubing 4 124 61 103 44 65 52 56 55 67 122

Case 1 Case 2 Case 3 Case 4 Case 5 Case 6 Case 7 Case 8 Case 9Case

10Case

11Case

12Case

13

Base Tension (Kips)

0

100

200

300

400

500

600

700

800

900

Outer Casing 724 549 538 576 616 624 619 469 549 802 616 650 508

Inner Cas ing 116 285 222 305 277 295 172 310 231 116 336 302 257

Tubing 93 187 173 141 130 103 142 154 153 105 187

Case 1 Case 2 Case 3 Case 4 Case 5 Case 6 Case 7 Case 8 Case 9 Case 10

Case 11

Case 12

Case 13

Top Tension (Kips)

Figure 15 Base Tension Distribution Results for Critical Pre-

stretch and Slack Off Loading Conditions Figure 16 Top Tension Distribution Results for Critical Pre-

stretch and Slack Off Loading Conditions

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Thook = 333.4kips(plus 80kips for handling equipment)

��������������

Taircan = 632kips 25kips due to friction now acts downwards

ull-Point 95ft above MWL

Stem Base at 512.8' belowMWL

Thook = 333.4kips(plus 80kips for handling equipment)

Taircan = 784kips 25kips due to friction acts downwards

Null-Point 95ft above MWL

Stem Base at 511.8' belowMWL

��������

Taircan = 784kips 25kips due to friction now acts upwards

Null-Point 95ft above MWL

Stem Base at 513.6ft below MWL

�������

a) Sample Stage 30 b) Sample Stage 33 c) Sample Stage 34

15685.5ft

��������������������������

Taircan = 1050kips25kips due to friction now acts upwards

Null-Point 95ft above MWL

Stem base is 513.5 below MWL

��������������������������

d) Sample Stage 39 e) Sample Stage 40

Thook = 178.9kips(plus 80kips for handling equip

15685.5ft

�����������

Taircan = 1050kips5kips due to friction now acts pwards

ull-Point 95ft above MWL

tem base is 512.5 below MWL

�����������

Figure 17 Sample Stages from Installation Sequence of Riser and Tubing

0

200

400

600

800

1000

1200

1400

1600

Stage Number of Installation Sequence

Tens

ion

(Kip

s)

Tension Provided by HookTension Provided by Aircan AssemblyOuter Casing Top TensionInner Casing Top Tension

Tubing Top Tension

Figure 18 Re-distribution of Tension in Outer and Inner Riser and Tubing During Critical Stages of Installation