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Holstein Combo Riser Testing And Analysis


OTC 17269 Holstein Combo Riser Testing and Analysis
F. Botros and W. Acuna, BP; G.W. Crotwell, Technip Offshore, Inc.; and R.M. Billings, Billings Metallurgical Services, Inc.

Copyright 2005, Offshore Technology Conference This paper was prepared for presentation at the 2005 Offshore Technology Conference held in Houston, TX, U.S.A., 2–5 May 2005. This paper was selected for presentation by an OTC Program Committee following review of information contained in a proposal 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 a proposal of not more than 300 words; illustrations may not be copied. The proposal 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.

The Holstein Well Systems team designed an evaluation program to confirm the suitability of the combo riser approach that included: ? ? ? ? ? toughness and fatigue crack growth rate testing of candidate riser materials simulation of drilling/completion damage to riser pipe evaluation and selection of in-situ inspection tools for detecting damage to the riser components identification and implementation of in-situ mitigation actions to minimize the likelihood of damage to riser components estimation of remaining fatigue lives of damaged riser components using fracture mechanics

Abstract This paper summarizes key aspects of work performed to demonstrate the suitability of a combination drilling/production riser concept for the Holstein Deepwater Development Project. Significant tasks included: toughness and fatigue crack growth rate testing of riser component materials; fracture mechanics-based fatigue life estimations; simulation and evaluation of drilling/completion damage to riser components; and evaluation and selection of in-situ riser inspection tools. Finally, the paper discusses a rational in-situ inspection program that could be implemented for the Holstein combo risers. Introduction The Holstein field lies in approximately 4344 ft of water in Green Canyon Blocks 644 and 645, 190 miles south of New Orleans, LA. To develop the field, BP selected a truss spar equipped with dry trees. A top tensioned, dual barrier riser system tied each of 15 wells (original appraisal well plus 14 others) back to its Christmas tree on the spar. BP set the minimum project life as 20 years. Additionally, operational plans called for water injection into the field for pressure maintenance and enhanced oil recovery. As such, the project design included souring of the reservoir during the life of the field. BP’s drilling strategy for Holstein involved using the platform rig to perform drilling and completion tasks through the production riser system on each well and hence the term combo riser. This strategy improved operational efficiency offshore during drilling and precluded the need for a dedicated drilling riser. However, the strategy also required an evaluation program to confirm the technical validity of using the Holstein risers for both drilling and production.

The remainder of this paper summarizes the testing and analysis that comprised the combo riser evaluation project. Additionally, the paper discusses a rational in-situ riser inspection program developed by Well Systems and Wells Delivery. Testing and Analysis Materials Testing. CTOD and fatigue crack growth rate tests were performed on candidate riser materials. The materials of interest included API 5L Grade X80 seamless line pipe, API 5CT Grade T95 Type I casing and two low alloy steel forging steels, ASTM A707 Grade III modified and ASTM A182 Grade F22 modified. The CTOD tests were performed in accordance with ASTM E1290 at a temperature of 32°F. The test specimen orientation was L-C. The fatigue crack growth rate testing was performed in accordance with ASTM E-647. The test configuration evaluated the straight line or Paris Law portion of the da/dN versus ?K curve. The lab performed the tests with the machine at constant load amplitude resulting in an increasing ?K test. The tests took place on L-C oriented specimens at room temperature in aerated ASTM substitute seawater. The procedure incorporated two test frequencies, 10 Hz and 10 cpm. Additionally, tests were performed at three different R ratios, 0.05, 0.5 and 0.75. During the tests the specimens were polarized to approximately -800 mv versus an Ag/AgCl reference electrode.

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Fatigue Life Estimation. The Well Systems team performed a series of fracture mechanics calculations to predict the fatigue lives of mechanically damaged riser components. The calculations assumed the presence of circumferential gouges of various lengths, depths and shapes on the inside surfaces of the inner and outer riser pipes. FEA provided the SCF associated with each specific gouge. Then, a commercially available computer program utilized the SCF for each gouge to determine the service life required to fail the riser in fatigue from the damaged area. The calculations incorporated the predicted riser loading spectra at the two most critical locations: the bottom of the keel joint and the top of the lower stress joint. Further, the calculations addressed different gouge cross sectional shapes judged to be the most representative of actual damage that may occur in the risers. Figure 1 shows the one casing string/riser component found that contained actual drilling damage. This part was the nose seal from an internal tie back connector. Consideration of the prevailing shape of the damage in this component coupled with consideration of available shapes provided in the software identified three gouge shapes for analyses: semi-circular, semi-elliptical and vee. Finally, to facilitate the calculations, the presence of a small circumferential crack centered at the bottom of each gouge was assumed. The assumed crack was 0.04 in. long by 0.01 in. deep. Damage Simulation. Because of a lack of damaged riser components available for examination, Well Systems and Well Delivery decided to simulate the damage that could occur during drilling and completing the Holstein wells. BP provided 20 lengths of 11-3/4” OD x 0.534 in. wall C-100 casing with integral box and pin connections. A service company installed the casing temporarily in an unpressured test well. After installation of the test casing, the service company ran five different planned Holstein BHA’s individually inside the casing. The BHA’s included an underreamer, a mill tooth bit and steerable mud motor, a PDC bit and stabilizer, a flat bottom mill and stabilizer and an RTTS packer. Each BHA was spotted in a separate length of casing, then rotated and reciprocated up and down over about a 10-foot length for 30 minutes. Figure 2 shows the configuration of the test string. Upon completion of the down hole work, the casing was recovered from the well. The five test lengths of casing were sectioned longitudinally full length. The exposed surfaces were then examined visually to characterize any damage. The damaged areas were inspected with a dry magnetic particle technique as well. Subsequently, several areas in the casing that appeared to be the most damaged were cut out. Then, plaster casts were made of the damage and the depths of the damaged areas were determined with the aid of an optical comparator. Inspection Tool Evaluation. This task involved identifying and then evaluating candidate tools that could be used to inspect the installed risers in place for mechanical damage. To

identify candidate inspection devices, Well Systems contacted all pipeline smart pig or inline inspection service vendors. We contacted a vendor that provides a mechanical caliper tool for tubing and casing inspection. We discussed the application with two vendors that provide ultrasonic inspection/logging tools commonly used to inspect well casing. And finally, we considered two different systems touted to provide complete ultrasonic inspection of drilling risers. Based on vendor interest in the Holstein application and on published technical performance, we identified an ultrasonic well logging tool as the most promising tool for the in-situ riser inspection. Two separate tasks made up the evaluation of the tool. In the first task, the logging company used the tool to inspect an “unknown” standard provided by BP. The standard, shown schematically in Figure 3, consisted of a 5-foot long section of 11-3/4” OD by 0.534” wall C-100 casing that contained an array of flaws machined in the inside surface. The flaws simulated extremely small areas of mechanical damage. Their lengths varied (circumferentially in the pipe) from 0.25 in. to 0.75 in. The flaw depth varied from 0.03 in. to 0.09 in. Each flaw had one of three different cross sectional shapes: semicircular, elliptical or vee. The logging work was performed in a laboratory setting. The fluids inside the standard during the inspection included either clear brine or Holstein drilling mud. The second evaluation task involved using the logging tool to inspect the casing in the test well during the previously discussed damage simulation task. In this case, the logging company inspected the casing string before and after the BHA’s were run in the hole. Additionally, the casing string included the BP “unknown” standard and the logging company inspected it as well. Presentation of Data and Results Materials Testing. All of the CTOD tests showed valid maximum load, ductile behavior. The δm values in inches obtained in the tests are shown below. X80 Line Pipe (outer riser) T95 Casing (inner riser) F22 Forging A707 Grade III Forging 0.023, 0.024, 0.026 0.010, 0.011, 0.012 0.042, 0.043, 0.046 0.040, 0.040, 0.041

Figures 4 through 7 show the results of the fatigue crack growth rate tests. Each figure also shows the mean design curve from BS 7910. As expected, lower test frequencies generally increased the crack growth rate. Increased R ratios had a similar effect. All the test results for all the materials were either conservative with respect to the mean BS 7910 curve or within 2 standard deviations of the mean curve. Fatigue Life Estimation. Tables 1 and 2 show the results of the fatigue life estimation calculations. In general, the calculations showed that significant damage was required to impair the riser fatigue life below the minimum required for the project, including a safety factor of 3. Additionally, the riser location just below the keel joint was a more fatigue

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critical location than that just above the stress joint. Also, due to lower CTOD properties and specific pipe dimensions, a damaged inner riser tended towards a lower fatigue life than a damaged outer riser. The calculations also showed that the semi-circular cross section flaw shape was the most severe followed by the vee shape and then the semi-elliptical shape. However, we believed this result was counterintuitive. Further analysis revealed that the calculation methodology overestimated the SCF associated with a semi-circular flaw shape. Consequently, we decided to ignore the semi-circular flaw shape calculations. In comparison to the calculation results, the damage to the nose seal in Figure 1 consisted almost entirely of smooth, semi-elliptically shaped scallops cut/gouged into the metal. The maximum depth of any gouge found in the seal was 0.041 in. Additionally, liquid penetrant inspection of the damage revealed no relevant linear indications. Damage Simulation. Visual inspection of the damaged casing lengths showed in fact that very little significant damaged occurred. The mud motor caused the most damage. The damage consisted almost entirely of smooth bottom scallops cut into the inner surface of the pipe. Figures 8 and 9 are views of this damage. Subsequent depth measurements made from casts of a number of representative locations ranged from 0.01 in. to 0.019 in. Magnetic particle inspection of the damaged areas revealed several possible indications of planar flaws. We removed these indications from the casing and examined them metallographically. Figures 10 and 11 representative views of typical MPI indications. Figures 12 and 13 are metallographs of the cross sections of the indications in Figures 10 and 11. The indications resulted from folds that formed in the metal from deformation caused by the BHA. Also, some of the indications appeared to be the results of manufacturing imperfections in the pipe. We found no evidence of cracking associated with the mechanical damage. The maximum depth of any of the MPI indications examined was 0.02 in. Inspection Tool Evaluation. The ultrasonic logging tool was able to provide complete coverage of the inside surface of the riser pipe. It detected all the flaws in the BP standard in both the laboratory and field environments. However, the probability of detection was most reliable for flaws that were both at least 0.75 in. long and 0.06 in. deep. Flaw shape did not influence the probability of detection. The tool was able to measure accurately the length of flaws that were at least 0.5 in. long. A high frequency transducer provided the best results in clear brine. A low frequency transducer was required in the drilling mud. The tool was unable to measure the depth of any of the flaws reliably. Additionally, it could not determine the cross sectional shape of a damaged area.

Conclusions The key conclusions from this work were: ? ? ? Likely consequences to the inside surface of a combo riser were identified. The Holstein BHA’s did not cause significant damage in the simulation work. Allowable metal loss was quantified. Calculations showed that significant mechanical damage was required to impact the fatigue life of the riser. An ultrasonic well logging tool was able to provide satisfactory in-situ inspection of the risers

Based on the conclusions listed above, BP decided that the combo riser approach was valid for Holstein. Consequently, the next task was to develop a reasonable inspection program for the risers. The program addressed both the acceptance criteria and the extent of the inspection work. Because of the sizing limitations of the inspection tool, acceptance criteria were established independently from the damage shape or depth. The results of the fatigue life calculations provided the basis for this effort. Figures 14 and 15 show, for the outer and inner risers respectively, plots of the cross sectional area of the gouge versus its calculated fatigue life. The plots concentrated only on the vee and semielliptical shaped gouges in these plots. Because the maximum depth of any damage observed on the nose seal and the test well casing was about 0.04 in., the plots neglected the 0.125inch deep vee-shaped gouges. On each graph, a line was fitted to represent the lower bound of the data. This line then indicated the damage cross sectional area at a fatigue life of 60 years, or three times the minimum required project life. Finally, we assumed a maximum gouge depth of 0.06 in. and determined the maximum allowable gouge length. For the outer riser pipe, this length was about 10 in. For the inner riser, the maximum allowable length was approximately 8 in. As for the extent of inspection, we considered the Holstein drilling strategy. In this strategy there were two groups of wells. One group of six (including the initial appraisal well) was pre-drilled to total depth from a MODU. These wells saw limited drilling and completion activities through the top tensioned risers. For the other group of nine wells, BP planned to perform significant drilling and all completion activities with the platform drill rig through the top tensioned risers. A multi-disciplined group discussed the risks associated with each group of wells. These discussions led to a reasonable inspection program that could be used if needed to reveal the condition of the inside riser surfaces, if desired, after drilling and completion activities. Table 3 details the inspection program that was developed. Acknowledgements The authors would like to thank BP Exploration and Production Inc. and Shell Offshore Inc. for their support of this work and for their permission to publish this paper. The authors would also like to thank Applied Mechanics, Halliburton and Weatherford for their participation in the work.

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Nomenclature BHA – bottom hole assembly Cpm – cycles per minute CTOD – crack tip opening displacement da/dN – fatigue crack growth rate per cycle δm – the value of CTOD at the first attainment of a maximum force plateau given fully plastic behavior FEA – finite element analysis MODU – mobile offshore drilling unit MPI – magnetic particle inspection PDC – polycrystalline diamond compact R ratio – the ratio of the minimum to maximum stress in fatigue testing RTTS – run and retrieve, test, treat, squeeze SCF – stress concentration factor Conversion Factors 1 ft. = 0.3048 m 1 in. = 25.4 mm 1 mile = 1.609 km

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Flaw Length, in. 0.55 1.1 0.75 3.0 1.5 3.0 2.0 8.0 2.0 4.0 6.0 8.0 2.0 4.0 6.0 8.0

Flaw Depth, in. 0.069 0.069 0.082 0.082 0.176 0.176 0.231 0.231 0.075 0.075 0.075 0.075 0.125 0.125 0.125 0.125

Depth/Wall, % 12.1 12.1 14.6 14.6 31 31 40.7 40.7 12.6 12.6 12.6 12.6 21 21 21 21

Semi-Elliptical Flaw 3287 1785 2795 1362 1182 255 609 0

Fatigue Life, Yrs Semi-Circular Flaw 576 448 412 288 148 80 48

Vee Shaped Flaw

2095 1860 1270 582 95 70 66 60

TABLE 1 Summary of Fatigue Life Calculations for Shaped Gouges in Outer Riser

Flaw Length, in. 0.55 1.1 0.75 3.0 1.5 3.0 2.0 8.0 2.0 4.0 6.0 8.0 2.0 4.0 6.0 8.0

Flaw Depth, in. 0.069 0.069 0.082 0.082 0.176 0.176 0.231 0.231 0.075 0.075 0.075 0.075 0.125 0.125 0.125 0.125

Depth/Wall, % 12.5 12.5 15 15 32 32 42 42 13.6 13.6 13.6 13.6 22.7 22.7 22.7 22.7

Semi-Elliptical Flaw 2563 1781 2049 1109 832 294 429 0

Fatigue Life, Yrs Semi-Circular Flaw 409 311 292 201 103 52 0 0

Vee Shaped Flaw

632 452 190 69 140 128 91 42

TABLE 2 Summary of Fatigue Life Calculations for Shaped Gouges in Inner Riser

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OUTER RISER Pre-drilled Wells ? No baseline inspection prior to in-hole work. ? Inspect the first riser installed (CAST-V image mode) o Inspect the stress joint; one riser joint above the stress joint; lower keel joint; one riser joint below the lower keel joint; and, any area indicated by in-hole activities (see Note 1). o If no significant damage is detected, inspect other risers only if required by in-hole activities. (Note 1). o If significant damage is detected, perform further evaluation of or replace the damaged joint and inspect all other risers as needed. ? Acceptance criteria will be determined from fatigue life vs. damage cross sectional area graph resulting from fracture mechanics calculations.

Platform Drilled Wells ? No baseline inspection prior to in-hole work. ? Inspect the first riser installed (CAST-V image mode) o Inspect the stress joint; one riser joint above the stress joint; lower keel joint; one riser joint below the lower keel joint; and, any area indicated by in-hole activities (see Note 1). o If no significant damage is detected, inspect other risers only if required by in-hole activities. (Note 1). o If significant damage is detected, perform further evaluation of or replace the damaged joint and inspect all other risers as needed. ? Acceptance criteria will be determined from fatigue life vs. damage cross sectional area graph resulting from fracture mechanics calculations.

INNER RISER Pre-drilled Wells ? No baseline inspection prior to in-hole work. ? Inspect risers for drilling wear (CAST-V) as indicated by the IMMS system. ? Inspect the first riser installed (CAST-V image mode) o Inspect the stress joint; one riser joint above the stress joint; lower keel joint; one riser joint below the lower keel joint; and, any area indicated by in-hole activities (see Note 1). o If no significant damage is detected, inspect other risers only if required by in-hole activities. (Note 1). o If significant damage is detected, perform further evaluation of or replace the damaged joint and inspect all other risers as needed. ? Acceptance criteria will be determined from fatigue life vs. damage cross sectional area graph resulting from fracture mechanics calculations. Platform Drilled Wells ? No baseline inspection prior to in-hole work. ? Inspect risers for drilling wear (CAST-V) as indicated by the IMMS system. ? Inspect the first riser installed (CAST-V image mode) o Inspect the stress joint; one riser joint above the stress joint; lower keel joint; one riser joint below the lower keel joint; and, any area indicated by in-hole activities (see Note 1). o If no significant damage is detected, inspect other risers only if required by in-hole activities. (Note 1). o If significant damage is detected, perform further evaluation of or replace the damaged joint and inspect all other risers as needed. ? Acceptance criteria will be determined from fatigue life vs. damage cross sectional area graph resulting from fracture mechanics calculations.

Note 1: In-hole activities of interest are those that could damage the riser (rotation of the BHA, stuck BHA, stuck completion equipment, stuck pipe, etc.).

TABLE 3 In-Situ Riser Inspection Program

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FIGURE 1 Internal Tie-Back Connector Nose Seal with Drilling Damage

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We a t he rford T e st We ll
Component 11 3/4" 65# C110 ANJO Casing Casing Casing Casing Casing Casing Casing Casing Casing Casing Casing Casing Casing Casing Casing Casing Casing Casing Standard Casing XO ANJO to 6 5/8" Reg XO 6 5/8" Reg to 4 1/2" XH 6 3/4" DC 6 3/4" DC 6 3/4" DC 6 3/4" DC 6 3/4" DC 30" casing 6 3/4" DC XO 6 5/8" Reg to 4 1/2" XH J-Slot Depth (ft) top # -10 20 Length (ft) 40 40 40 40 40 40 40 40 40 40 40 40 40 40 40 40 40 40 40 11 40 6 4 30 30 30 30 30 30 4 2

30 19 70 18 110 17 150 16 15 190 230 14 270 13 12 310 350 11 390 10 9 430 8 470 7 510 6 550 5 590 4 630 3 670 2 710 750 1 761 801 XO 807 6 811 5 841 871 4 901 3 931 961 2 1

991 995 J-slt

20" Casing

1500

FIGURE 2 Configuration of the Test Well Casing String

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FIGURE 3 Schematic (unrolled pipe cylinder) of BP Inspection Standard

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X80 Cathodic Protection

T95 Cathodic Protection

0.01

1.00E-02

X80-1 10 Hz R=0.05 CP X80-2 10Hz R=0.05 CP X80-3 10Hz R=0.75 CP
0.001

X80-4 10cpm R=0.75 CP BS7910 Design Curve

1.00E-03

0.0001

1.00E-04

T95-4 10 CPM R=0.05 T95-4 10 Hz R=0.05 T95-5 10 Hz R=0.5 T95-6 10 Hz R=0.75 T95-3 10 Hz R=0.05 T95-2 10 Hz R=0.5 T95-2 10 Hz R=0.05 T95-1 10 Hz R=0.05 T95-1 10 CPM R=0.05 BS7910 Design Curve

1E-05

1.00E-05

da/dN, inch/cycle

1E-06

da/dN, inch/cycle
10.00 ?K, Ksi-inch0.5 100.00

1.00E-06

1E-07

1.00E-07

1E-08

1.00E-08

1E-09

1.00E-09

1E-10 1.00

1.00E-10 1 10 ?K, Ksi-inch0.5 100

FIGURE 4 Fatigue Crack Growth Rate Data for X80 Line Pipe

FIGURE 5 Fatigue Crack Growth Rate Data for T95 Casing

F22 Cathodic Protection

A707 Cathodic Protection

0.01

0.01

0.001

F22-1 10hz R=0.5 CP F22-2 10hz R=0.5 CP F22-3 10cpm R=0.75 CP F22s-1 10cpm R=0.75 CP F22s-2 10cpm R=0.5 CP F22s-3 10cpm R=0.5 CP BS7910 Design Curve

0.001

A707-1 10hz R=0.5 CP A707-2 10hz R=0.5 CP A707-3 10hz R=0.75 CP A707S-1 10cpm R=0.5 CP A707s-3 10cpm R=0.75 CP BS7910 Design Curve

0.0001

0.0001

1E-05

1E-05

da/dN, inch/cycle

1E-06

da/dN, inch/cycle 10.00 ?K, Ksi-inch0.5 100.00

1E-06

1E-07

1E-07

1E-08

1E-08

1E-09

1E-09

1E-10 1.00

1E-10 1.00

10.00 ?K, Ksi-inch0.5

100.00

FIGURE 6 Fatigue Crack Growth Rate Data for F22 Forging

FIGURE 7 Fatigue Crack Growth Rate Data for A707 Forgings

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FIGURE 8 Overview of Mud Motor Damage Inside Casing

FIGURE 9 Close Up View of Mud Motor Damage in Casing

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FIGURE 10 MPI Indication on ID of Test Casing Subjected to Flat Bottom Mill

FIGURE 11 MPI Indications on ID of Test Casing Subjected to Underreamer

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FIGURE 12 Photomicrograph of Damage from Figure 10

FIGURE 13 Photomicrograph of Damage from Figure 11 (lines are scratches from polishing process)

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1200 1100 1000 900 800 Fatigue Life, Yrs 700 600 500 400 300 200 100 0 0.0 0.2 0.4 0.6 0.8 1.0 1.2 1.4 1.6 1.8 2.0 Damage Area, Sq In Elliptical at KJ V-notch 075 at KJ Elliptical at SJ V-notch 075 at SJ

FIGURE 14 Plot of Damage Area vs. Fatigue Life for Outer Riser

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1200 1100 1000 900 800 Fatigue Life, Yrs 700 600 500 400 300 200 100 0 0.0 0.2 0.4 0.6 0.8 1.0 1.2 1.4 1.6 1.8 2.0 Damage Area, Sq In Elliptical at KJ V-notch 075 at KJ Elliptical at SJ V-notch 075 at SJ

FIGURE 15 Plot of Damage Area vs. Fatigue Life for Inner Riser


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