Well Experts

Ormen Lange Wells

1 02.12.2005 BSA EK MP

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Report Prepared by

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Approved by

Document Control Sheet

Title: Ormen Lange Author(s): Bernt S. Aadnøy

Issue Date: 02.12.2005

Document Number: WE 00105

Approval: Approved by:

_____________________

Mike Pollard,

Project Manager, Well Experts Location / Hardcopy

Last Update Time Check: 02 December 2005

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Ormen Lange Wells

A report presented to the Norwegian Petroleum Authority by Well Experts.

Contents: Page: 1. Summary 2 2. Description of audit 3 3. The construction of Ormen Lange wells 4 4. Review of important issues 5 4.1 Qualification of equipment 4.2 Pressure testing of the TRSSSV 4.3 TRSCSSV - Downhole safety valve 4.3.1 Non-equalizing valve 4.3.2 Equalizing valve 4.4 Tubing hanger 4.5 Tubing connectors

4.6 Liner hanger 4.7 Lower completion 4.8 Contingencies 4.9 Training and personnel involvement 5. Outstanding issues 15 Summary 15 Nomenclature 16 References 16

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1. Summary This report presents a short review of the Ormen Lange wells. The well design is evaluated, and the test reports for some critical downhole components are evaluated. The design and the planning are well carried out to a considerable detail level, a work of high quality. Critical components have undergone extensive testing, which qualifies them. Some testing is in its final phase. Although alternative solutions are possible, no major problems were discovered in the review.

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2. Description of audit. This audit is one of several audits regarding well design towards operators on the Norwegian shelf. The objective is to review Shell/Norsk Hydro practices for well barriers, surveillance and testing, and, qualification and application of new technology. Petroleumstilsynet has performed similar audits towards several operating companies, with different focus. Usually it has been performed after incidents like well failures. This particular audit is different as it is performed before the Ormen Lange field is developed. The Ormen Lange wells are the first gas wells on the Norwegian continental shelf producing through 9-5/8 in. production tubing, called "big-bore" wells. The large production rates from these wells require application and qualification of new technology. This audit is limited to the well. This audit will not review all of the documentation developed for the project, only selected reports directly related to the audit. The participants are from the Petroleum Safety Authority: Sissel Østbø, team leader Hilde H. Løken Arne M. Enoksen Bernt S. Aadnøy, advisor

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3. The construction of Ormen Lange wells An overview of the selected base case design will be presented below.

Figure 3.1: Base case design for Ormen Lange pre-drilled wells. The design shown is a result of many analyses. Some design factors are:

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-A long 9-5/8 in. liner from top reservoir to intermediate casing to eliminate borehole stability problems in the Rogaland shales.

-Two production/completion packers where both the 7 in. and the 9-5/8 in liners is part of the production strings. -9-5/8 in. production tubing, called a "big-bore" producer. -Double downhole safety valves, deep set to avoid hydrate problems.

The completion is a simple design. The wells are designed for 20 years of operation without workover. In addition to a robust design, all equipment is quality checked. In this report we will not present further description of the wells, but refer to the comprehensive main drilling programme, ref.1, which contains the following chapters:

1. Non-conformances and HSEQ 2. General Information 3. Well objectives 4. Delivering scope contingency and flexibility 5. Operating schedules 6. Location data 7. Geophysics and geology 8. Reservoir technology 9. Formation evaluation and data acquisition 10. Drilling and completions fluids 11. Cementing fluids philosophy 12. Directional drilling 13. Casing design 14. Subsea 15. Completion 16. Well clean up 17. Operations 18. Activity summary 19. Appendix A: Template locations, safe handling zones and seabed layout maps 20. Appendix B: Formation evaluation and data acquisition 21. Appendix C: Drilling and completion fluids 22. Appendix D: Hole cleaning 23. Appendix E: Cement programme 24. Appendix F: Directional drilling 25. Appendix G: Casing design 26. Appendix H: Subsea equipment 27. Appendix I: Completion design 28. Appendix J: Operation schedules 29. Appendix K: Blow Out Preventer (BOP) Diagram 30. Appendix L: Drilling hazards of offset wells 31. Appendix M: Barrier diagrams 32. Appendix N: Well suspension and abandonment 33. Appendix O: Wellhead and conductor interface diagram

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34. Appendix P: Relief well trajectories 35. Appendix Q: List of abbreviations 36 Appendix R: List of figures

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4. Review of some important issues 4.1 Qualification of equipment The operators identified early in the development equipment that have critical functions, are new technology or may fail due to excessive loads. In the following we will present the results from some of these equipment qualifications. The most relevant regulations are given in the PSA Facilities Regulations (ref. 2). Here the requirement for a downhole safety valve is defined, and also qualification requirements and load determination requirements. The PSA Activities Regulations (ref. 3) defines the regulations related to the operations. We will in the following address a few aspects from these regulations. 4.2 Pressure testing of the TRSSSV The PSA Activities Regulations (ref. 3) section 44 is important for the present analysis. The Maintenance program section 44g) states: "The NORSOK D-010 standard, chapters 5.2, 5.3, and 5.4, the ISO 10417 standard and the ISO 10423 standard chapter 9 should be used for well control and well intervention equipment, subsurface safety valves and Christmas threes with the following additions: a)…. b)….

c) In a new well, the Christmas three and all valves subjected to well pressure should be pressure tested to design pressure upon installation and at least once every third month thereafter, d) All newly installed subsurface safety valves should be pressure tested in the direction of flow every month for three months before the interval can be increased to three months. Christmas threes and subsurface safety valves should be tested every third month at least three times before the interval can be increased to six months. e) Valves to the production annulus should be tested to the same interval as the Christmas threes.

…” The issue of pressure testing has been a subject of discussion. A reduced test frequency might be preferable from an operational point of view; however, this is not acceptable according to regulations. Shell has developed a plan to analyze and approach this issue as follows. The following is a quote from a Status note (ref. 4).

"Background

In a presentation given to Ptil on March 2nd 2005 regarding the status of the TR-SSSV qualification testing, the Ormen Lange team indicated that a reduction of the regulatory inflow test frequency was being considered. Main considerations for reducing the test frequency are:

-Ormen Lange TR-SSSV is not "off the shelf", but has undergone very extensive qualification testing tailored to worst-case Ormen Lange Operating conditions.

-The Ormen Lange configuration, with dual hot-stacked TR-SSSVs with independent control lines and subsea wells at 850 m water depth, will have a considerably lower overall risk than other fields in the Norwegian sector.

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-The operational risks associated with frequent inflow testing, for example due to hydrates or formation damage caused by MEG injection into the wells, can become significant for Ormen Lange.

In a meeting with Ptil on October 20th 2005, the options for valve integrity testing were presented. As part of the way forward, it was indicated how the project intends to further pursue the issue of testing frequency. As requested at this meeting, this note presents a short view of the ongoing and planned work regarding testing frequencies.

Workplan TR-SSSV Testing Frequencies

1. Decision on self-equalizing TR-SSSV

A non-equalizing TR-SSSV has been qualified for Ormen Lange. Qualification testing of the self-equalizing version of that valve is currently undergoing. In case of a successful test, the decision will be taken to use self-equalizing TR-SSSVs for Ormen Lange wells. In case the test is not successful, the Ormen Lange wells will be equipped with the qualified non-equalizing TR-SSSVs.

2. Risk study with Exprosoft

A study will be carried out by Exprosoft to investigate the following aspects:

-Overall safety availability of primary and secondary well barriers as a function of alternative test philosophies and testing frequencies.

-Comparison between Ormen Lange risk levels and comparable fields.

The study will be carried out in Q1 and Q2 of 2006, with a final report expected by July 2006.

3. Evaluation of Exprosoft study and potential application for exemption

The Exprosoft study and consequences for Ormen Lange will be evaluated. Based on the overall risk levels for Ormen Lange compared to other fields in the Norwegian sector, the preferred testing philosophy and optimum testing frequency will be determined.

The results of the study and the consequences for Ormen Lange will be discussed with Ptil. In case the optimum testing frequencies are not in accordance with the applicable regulations, a formal exemption will then be applied for."

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4.3 TRSCSSV - Downhole safety valve The downhole safety valve is a critical element. Two of these will be installed in each well. Because 7 in. valves are required, new technology is needed. Shell decided to test valves from three vendors, Baker-Hughes, Halliburton and Schlumberger. Each of these vendors delivered valves to be tested by DNV. The valves were initially run through an extensive test programme where all valves failed initially. Ref. 5 summarizes these initial tests. The objective for the first tests was to establish basis for further review and testing. 4.3.1 Non-equalizing safety valve Reference 6 defines the procedures for the tests, whereas Ref.7, summarize results from further testing. Below we will quote the conclusions from this study:

"The Baker Oil Tools TRSCSSV, model TSM-5 SS prototype, as redesigned 2004, was found to be the best alternative among the 3 for the Ormen Lange application. This is mainly because it sustained the demanding conditions during closing in a flowing gas well than the other valves.

It did not, however, seal well at low differential pressure across the flapper, for which the Halliburton valve sealed best.

Therefore the recommendation for the Baker valve is subject to one condition: The differential pressure to be applied during the field valve leak tests (inflow tests) will be above 30 bar. The time for field leak tests increases significantly for the Ormen Lange gas well TRSCSSV with increased differential pressure between the flowline and the well.

There are also subjects identified that should be followed up prior to and during manufacturing of the production valves. Most of these apply to all valves requiring high reliability and thereby also the Baker valve:

One should verify by adequate in-house tests the lower limit of the differential pressure when:

- The valve has been exposed/contaminated by fines

- The gas pressure is released slowly at the same time as the valve is in 45 deg. position with the flapper pin pointing slanted upwards, as the leak test combined conditions from test 5 and 6. The detailed test procedure should be evaluated when the field test procedure has been established. This could be conducted at the manufacturers test facilities by simple means, provided sufficient gas can be made available.

Specific items for quality assurance follow up are:

1. To specify tighter acceptance criteria for leak rates during the manufacturers QC test in the workshop. 2. Improve the QC on the component dimensions and actual materials in general. 3. Improve the QC on the dimensional tolerances stack-up that affects the flapper hinge clearances/performance. 4. Improve the QC on the filing system for manufacturers documentation.

All valves' flapper hinge components have been deformed. It is therefore assumed that this is impractical to avoid as long as a valve type with a flapper design is used.

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The second valve alternative is the Halliburton valve. This valve should be redesigned with respect to its internal components' ability to absorb the forces caused by closure in a flowing well. The components of most concern would be the flow tube and the flow tube upward end stop arrangement. The latter should also assure that the hydraulic piston is not subject to the violent impact forces from the flow-tube after the piston has reached its end stop.

The third valve alternative is the Schlumberger valve. This should be redesigned with respect to its secondary seal, flow tube and reduced opening pressure.

The Lock Open Tools.

The Baker LOT successfully passed the in-house tests and the DTL 3rd party test. The LOT supplied by Halliburton and Schlumberger were not subject to tests at DTL because of their deformed flow tubes. A subsequent in-house test with the Halliburton LOT after the gas slam tests at the Halliburton facility was attempted without success.

Further, the LOT for both Halliburton and Schlumberger were assessed to have more uncertain design and operational features that the Baker LOT."

As seen above, Bakers valve were found to be the best. This non-equalising valve is accepted with the concerns identified above. 4.3.2 Equalizing safety valve Both equalising and non-equalising safety valves are considered for Ormen Lange. These two concepts have some differences in application, especially related to pressure tests. A qualification test was conducted on an equalising Baker TRSCSSV. The report of these tests is given in Ref. 8. This valve did not qualify. Below is a summary from ref. 8: "1.2.1.1 Equalising valve

The valve equalising function failed after the final test at the final slam. After disassembly it was observed that parts of the equalising poppet valve were missing. It was concluded that the parts may have disappeared due to the total number of valve operations including the slams, not only the final slam. This assumption was based on the fact that there were no parts or bonding compound left in the threaded hole for the screw keeping the parts in place.

Otherwise the small size of the equalising valve require a long time for pressure equalising in offshore leak tests, as predicted (Ref.: DNV rep. 2004-1014-R3). The vent rate recorded during the tests was measured to a magnitude 2.8 Sm3/min for start venting 5 MPa over a differential pressure of 1.9 MPa. Some disturbances early are the test phase could have resulted in a tolerance problem caused by the flow-tube entering the space outside the plunger. A tolerance study indicates that this is a slight possibility."

Our understanding is that the equalising valve did not pass the tests, and that further development and testing will be carried out. 4.4 Tubing hanger During selection of the tubing hanger one chose different strength and steel qualities in tubing and hanger. It was decided to carry out a test program to qualify the tubing hanger. The test report is expected at the end of 2005.

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4.5 Tubing connectors The tubing connectors on the 7 in. production are of the type SM13CrM110 VAM TOP HC type. Test programs for the connectors is given in Ref. 9. In this test program the connectors were loaded to 90 % of the yield strength in tension, compression and in internal and external pressures. In addition, maximum and minimum torque values were applied. All six specimens passed the tests successfully. The connectors are further tested by Sumitomo, refs. 10, 11. Ref. 10 successfully tested the seal tightness properties of the connections, whereas Ref. 11 checked the make up torque, studied thread galling and confirmed that the connection can be rated to 100 % in tension. Test programs for the 9-5/8 in. and the 13-3/8 in. connections are under way. Reports expected at the end of 2005. 4.6 Liner hanger The liner hanger is a weak link with respect to possible leaks to seabed. After considering several scenarios, the following is the chosen solution for Ormen Lange. The 9-5/8 in. liner hanger is set inside the 13-3/8 in. production casing. Both the 9-5/8 in and the 13-3/8 in casings constitutes the production casing. The liner is placed on top reservoir, and will be cemented minimum 200 m. The production packer is set inside the 9-5/8 in liner. The test report for the liner hanger is expected at the end of 2005. 4.7 Lower completion Ormen Lange has a high potential for sand production. For that reason gravel packs and sand screen has been designed for the flow conditions expected. A considerable qualification and testing of equipment is performed. FIV is used during the completion operation to avoid MEG to contact the reservoir and lead to production impairment. This valve is also quality checked. When the gravel pack is installed, the FIV will close. The FIV can be tested from both sides, and have a success ratio of 98 %. If the FIV test is not positive, it will be closed/open over again. If the second test is not acceptable, another Halliburton bridge plug will be set in the 7 in. tubing. The test report for the lower completion is expected at the end of 2005. 4.8 Contingencies Because problems may arise during drilling of some of the wells, some contingency solutions are planned. Below a brief summary of some contingencies will be presented.

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Damage to 13-3/8 in. casing If damage is detected in the intermediate casing before drilling the 12-1/4 in hole, a sidetrack will be drilled from the 20 in. casing. Alternatively, if intermediate casing damage is detected after setting the 9-5/8 in. liner, there are several contingency solutions. If a leak is detected in the upper part of the 13-3/8 in. casing, a tieback casing may be installed, consisting of a 10-3/4 x 9-5/8 in casing (scab liner). The drawback is that this limits the completion to a 7 in. system. An expandable clad is also considered. This solution depends of the position of the damage and the clearance. Under optimal condition the full 9-5-8 in production system can be kept. Shallow setting of 9-5/8 in. liner During drilling the 9-5/8 in liner may not reach designed setting depth. Reasons can be borehole stability issues or simply mechanical liner landing problems. For this case several options exists. Drilling can continue to top reservoir. An expandable casing can be placed across the open hole. The reservoir can be drilled to TD with an 8-1/2 in. hole. One may also drill directly to TD and set a liner down to top reservoir. Alternatively can both options be used but with cemented liner. Damage in 9-5/8 in. liner or liner hanger For this case a tieback packer will be set inside the 13-3/8 in. casing. Integrity failure in a shallow hydraulic liner hanger, may be solved by installing an expandable 7-5/8 in x 9-5/8 in expandable. This is a more complex solution but beneficial from a production point of view. Finally, if damage occurs deep in the 9-5/8 in liner, a sidetrack is the option. Ref. 12 gives a detailed presentation of various contingency configurations that may arise during the drilling phase of the wells. The following chapters are presented:

1. Scope 2. Conductor cementation and position 3. Unable to land and lock the conductor 4. Surface casing cementing and running 5. Lack of integrity in 20" surface casing 6. Hole problems and losses below 20" shoe 7. Contingency in the 12-1/4" OH for the production liner 8. Contingency for inadequate 13 5/8" shoe strength 9. Inadequate shoe strength at the top reservoir 10. Failed 13 5/8" casing 11. Shallow set 9 5/8" liner 12. Damage 9 5/8" liner/liner hanger 13. Side track contingency 14. Pilot hole contingencies 15. Decision matrix for Contingency Configurations 16. Final barrier status for selected contingency configurations

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4.9 Training and personnel involvement Shell has developed KM (Knowledge Management), which is a system and a database that containes history, ongoing operations, questions/answers and experiences from other wells. The main objective is to make important information available. It is not replacing other reporting systems, but it is developed because Shell found gaps in other information exchange systems. The Risk register is a live document, intended to contain all risks evaluations around a project or an operation. Conventional HAZIDs and HAZOPs are intended reduced and replaced. SIMOPS is an important issue. DNV is working on identifying risks with falling objects on the template. Safety zones will be established. Only one derrick will be used to work on the wells, even if West Navigator is equipped with two derricks. The other derrick will be used for preparatory work.

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5. Outstanding issues At the date of this report, the following reports are not finished. Final test report for the equalising TRSCSSV. The second report on the equalizing safety valve is expected at the end of 2005. After that, a decision will be made of which of the two valve types will be installed on Ormen Lange. Lower completion (gravel pack - screens). This report is expected in week 47, 2005 Connection testing of 9-5/8" and 13-3/8" connections. Report expected mid-December 2005. Testing of tubing hanger and liner hanger Report expected week 47 2005. Strategy for pressure testing of downhole safety valves. Expected established July 2006. Summary This report presents a short review of the design of the Ormen Lange wells. The well design is evaluated, and the test reports for some critical downhole components are evaluated. The design and the planning are well carried out to a considerable detail level, a work of high quality. Critical components have undergone extensive testing, which qualifies them. Some testing is in its final phase. Although alternative solutions are possible, no major problems were discovered in the review.

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Nomenclature HSEQ Health, Safety and Equipment Qualification TRSCSSV downhole safety valve QC quality control LOT lock-open tool MEG metyl etylen glykol FIV flow valve KM knowledge management SIMOPS simultaneous operations HAZID/HAZOP hazard analysis PSA Petroleum Safety Authority (Ptil) DNV Det Norske Veritas References 1. Ormen Lange Main Drilling and Completion Programme. Doc. No. 37-1B-NS-K15-007, Final, 01.12.2004A/S Norske Shell E and P Ormen Lange. 2. Regulations Relating to Design and Outfitting of Facilities etc. in the Petroleum Activities (The Facilities Regulations). Petroleum Safety Authority Norway (PSA) 3 Sept. 2001. 3. Guidelines to Regulations Relating to Conduct of Activities in the Petroleum Activities (The Activities Regulations). Petroleum Safety Authority Norway (PSA), 1 January 2002 (Updated 1 January 2005). 4. Status Note: Ormen Lange - Ongoing and planned work regarding inflow testing frequencies of sub-surface safety and tree valves. A/S Norske Shell E&P Ormen Lange, from Roel Aretz, date 15.11.2005. 5. TRSCSSV test data overview and basis for conclusions. ExproSoft DNV, Doc. no.: 2004-DNVEx-3-041. 6. Qualification procedures for new technology. Recommended Practice DNV-RP-A203, Sept. 2001, Det Norske Veritas. 7. TRSCSSVs - Ormen Lange application - Comparison. Report No. 2-20, Det Norske Veritas, date: 2004-11-12. 8. Baker Equalising TRSCSSV Tests 2005. Report No.C20,Det Norske Veritas. date: 2005-06-21 9. Test Results Summary of 7" 32.0 # SM13CrM110 VAM TOP HC for Norsk Hydro Ormen Lange Project. R&D Job No. IR140. VAM PTS Company, date 6-20-05. 10. Qualification Test Results of 7" x 32.0# SM13CRM-110 x F6NM75 VAM TOP HC Tubing Hanger. Report G3130, Sumitomo Metal Industries, October 2005. 11. Qualification Test Results of 7" x 32.0# SM13CRM-110 x AISI420 VAM TOP HC Tubing Hanger. Report G3131, Sumitomo Metal Industries, October 2005. 12. Ormen Lange Contingency Well Configurations. A/S Norske Shell E&P Ormen Lange. Doc. date: 05.12.2004

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