Upstream Risk Management AS

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CONTENTS Contents ..................................................................................................................................... 1 Examples: Life-cycle cost/profit studies ................................................................................. 2

Availability study of DHSV concept for the Shtokman field ................................................. 4 Evaluation of Completion Intervention Requirement at the Haltenbank ............................... 4 Intervention Requirement Study for Gjøa .............................................................................. 4 Intervention Requirement Study for the Ormen Lange Field Development .......................... 4 Intervention Study for the Aasgard Field ............................................................................... 4 Mariscal Sucre LNG Development: Intervention and OPEX study ....................................... 4 Operational Risk Assessment of Goliat Subsea Wells ........................................................... 5 Regularity study of Lunskoye gas wells ................................................................................. 5 Risk Assessment of Tyrihans Completions ............................................................................ 5 Risk Assessment of Corrib Subsea Wells ............................................................................... 5 Tandem SCSSV Study for NAM Unmanned Platforms ........................................................ 5

Examples: Asset Integrity/Risk Assessments ......................................................................... 6 Vega R-12H Wellbore QRA ................................................................................................... 8 Gimle C-18AT2 Well P&A Risk Review .............................................................................. 9 Well Risk Analysis in Gullfaks Field ..................................................................................... 8 QRA for TRSCSSV concept selection in Norg UGS ............................................................. 8 Gas Lift Well Risk Analysis for Sarawak Shell Berhad ......................................................... 9 Risk Analysis of Annular Safety Valve vs. Wellhead Check Valves for Gas Lifted Platform Wells ....................................................................................................................................... 9 Risk analysis of Njord well barrier failure ............................................................................. 9 Risk analysis of Tune well barrier failure .............................................................................. 9 Risk Analysis of Varg A Wellhead Platform Gas Lift Wells ................................................. 9 Risk evaluation of Brage tubing hangers ................................................................................ 9

References to case studies ...................................................................................................... 11

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EXAMPLES: ASSET LIFE-CYCLE COST/PROFIT STUDIES LCC/LCP studies presented are based on use of relevant input reliability data that is collected together with client, but also generic data from the WellMaster, OREDA and SubseaMaster JIP reliability databases. Further, the studies may be analytically based or by means of Monte Carlo simulations such as Pipeline Inspection Optimiser, Maintenance Optimiser or Well LCC capable of LCC analysis of most common well designs and intervention strategies:

Figure 1. PIO is an example tool developed by UPSRM for an operation that help find the optimal balance between cost of failures (numbers and when they occur) vs. cost of preventive maintenance tasks (numbers and when they occur) of degradable systems

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Figure 2. Maintenance Optimiser is example of baseline screening tools developed for maintenance planning and optimisation as quick alternatives to more rigorous tool (gloryRCM) and studies offered by UPSRM.

Figure 3. Well LCC is an example of baseline LCC/LCP tool developed for client analysis of single wells as alternative to more rigorous tools and studies offered by UPSRM. Well system performance measures that often are focused in such studies are: (i) Well/Field intervention costs (OPEX). (ii) Well/Field intervention frequency, (iii) Well downtime and well/field production availability (production losses).

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AVAILABILITY STUDY OF DHSV CONCEPT FOR THE SHTOKMAN FIELD This study included resulted from an early assessment of downhole safety valve configuration concepts considered for the wells in the Shtokman field. The following well cases were defined and analysed: Base Case: Single gas production well with a single downhole safety valve (DHSV) including single hydraulic control line. Case 1: Single gas production well with two DHSVs with single control lines in a hot backup configuration. Otherwise as for the Base Case. The production availability of the well cases were modelled and analysed under the assumption of a four-month ‘summer season’ for performing interventions.

EVALUATION OF COMPLETION INTERVENTION REQUIREMENT AT THE HALTENBANK The objective of the study was to quantify basic rig intervention requirement related to downhole failures for different subsea completion configurations utilised at the Haltenbanken area. A coarse analysis was performed based on analytical modelling.

INTERVENTION REQUIREMENT STUDY FOR GJØA This report documents a reliability assessment made for the Base Case well completion design options proposed for the Gjøa field development. On the basis of a proposed field development plan, the following basic field well case was defined and analysed: Base Case (BC): All wells in field include a single tubing retrievable safety valve (TR-SCSSV) with insert capability. I.e., an insert safety valve (WR-SCSSV) can be run as a replacement inside the TR-SCSSV in most situations of TR-SCSSV failure. Redundancy assumed between DIACS valves in the DIACS configured wells. I.e., that only failure to operate or open both DIACS valves on demand will introduce the need for one or more (on average every three required DIACS year) light well interventions to carry out production logging (PLT) or to mechanically operate the DIACS valve.

INTERVENTION REQUIREMENT STUDY FOR THE ORMEN LANGE FIELD DEVELOPMENT The study was based on an assumed Case A completion alternative for an Ormen Lange big-bore gas well.

INTERVENTION STUDY FOR THE AASGARD FIELD This report gives an evaluation of the Aasgard well intervention requirements. The analysis included all types of wells. For each well type the following case analyses were performed: (i) Insert of WR-SCSSV in the event of TR-SCSSV failure. (ii) Replacement of TR-SCSSV in the event of TR-SCSSV failure

MARISCAL SUCRE LNG DEVELOPMENT: INTERVENTION AND OPEX STUDY This report documents an Operating Expenses (OPEX) study of development options for Mariscal Sucre LNG (MSLNG) project offshore Venezuela. The project objective was to quantify the operational cost range of the different field development options as a result of intrinsic well equipment failures. Two well cases were established and analysed for two different intervention strategies as part of the study: (i) Dry and subsea X-mas tree gas wells with immediate failure remediation of upper completion and wellhead/subsea equipment as required to minimise well downtime and safety unavailability. (ii) Dry and subsea X-mas tree gas wells with average 5-year periodic rig intervention following field drilling campaigns to minimise rig intervention costs. Note however that light vessel and surface remediation work in this case was performed immediately as required.

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OPERATIONAL RISK ASSESSMENT OF GOLIAT SUBSEA WELLS This report documents an operational risk assessment made for different well completion design options proposed for gas lifted oil producers (OP) at the Goliat field development: Base Case (BC): 2-Zone DIACS well with a single tubing retrievable safety valve (TR-SCSSV) including dual redundant hydraulic controls and insert valve capability. Case 1 (C1): Well included two TR-SCSSVs with single control lines in a hot backup configuration. Case 2A/B (C2A/C2B): Well included a packer type annulus safety valve system (ASV). Two distinct operational philosophies were assessed for this case. A traditional situation where the ASV system is considered the only well primary barrier on the A-annulus side and an alternative situation where the ASV is considered redundant as primary well barrier with the production string below the ASV packer. Case 3 (C3): Well without DIACS.

REGULARITY STUDY OF LUNSKOYE GAS WELLS Includes a study of the large bore (9 5/8”) gas production wells at the Lunskoye field. The project objective was to quantify the operational performance measures of the wells as a result of intrinsic equipment failures and planned well interventions.

RISK ASSESSMENT OF TYRIHANS COMPLETIONS This report documents a reliability assessment made for well completion design options proposed for the Tyrihans field development. The study report covers an initial assessment of well design concept for subsurface safety valve and downhole instrumentation and control system (DIACS): Base Case: All wells in field include a single tubing retrievable safety valve (TR-SCSSV) with insert capability. No redundancy assumed between DIACS valves in wells. Case 1: All wells in field include two tubing retrievable safety valves with insert capability in a “hot” backup/tandem configuration. No redundancy assumed between DIACS valves in wells. Case 2: As Base Case, except that the two DIACS valves in the DIACS configured wells are considered redundant. In addition, sensitivity studies were performed to assess the impact of uncertainty in the DIACS systems reliability data.

RISK ASSESSMENT OF CORRIB SUBSEA WELLS This report documents a reliability assessment made for the five subsea wells planned at the Corrib gas field development. The field case (well cluster) defined and analysed: (i) All wells in field include a horizontal X-mas tree. (ii) All wells involve a conventional completion with sliding sleeve, PBR seal assembly and a single tubing retrievable safety valve (TR-SCSSV) with insert valve capability (WR-SCSSV). Note in particular related to well downtime that the Corrib field is subject to severe sea currents and weather conditions in the winter season (October through February) making work on the wells in this period very difficult. A special focus of the study was therefore impacts of seasonal variations in well maintenance work on the gas delivery requirements of the field.

TANDEM SCSSV STUDY FOR NAM UNMANNED PLATFORMS This study comprised a combined LCC/LCP and risk analysis made for gas wells on the basis of intervention logistics, downhole safety valve concepts and well barrier test intervals: Base Case: Dry tree well with a single tubing retrievable safety valve (TR-SCSSV) with insert capability. 6 or 12 months test interval assumed for SCSSV and X-mas tree master valve. Case 1: Dry tree well with two tubing retrievable safety valves (TR-SCSSV) with insert capability in a hot back-up configuration. 6 or 12 months test interval assumed for SCSSV and X-mas tree master valve. As part of the study, the operational performance of the well cases for three different platform types (manned, unmanned with helicopter deck and crane, unmanned without helicopter deck or crane) were modelled and analysed.

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EXAMPLES: ASSET INTEGRITY/RISK ASSESSMENTS Risk Assessment studies presented are based on use of relevant input reliability data that is collected together with client, but also generic data from the WellMaster, OREDA and SubseaMaster JIP reliability databases. Further, the analysis may often be based on traditional well barrier and fault-tree analysis, but also recently due to new barrier requirements, coupled with modern risk analysis tools e.g. PPA Solution Optimiser, SIL Reliability Allocator, Kick Margin Risk, WPRA-H (human reliability analysis) and BOP system SIL Optimiser:

Figure 4. PASO is an example tool developed by UPSRM for an operator to help find a sound balance between required costs of PPA operations (the solution selected) versus reasonable acceptance criteria established by operator for well system leak probabilities.

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Figure 5. SIL Reliability Allocator is an example tool developed by UPSRM to help find an optimal balance between SIL system costs (the solution selected) and required asset risk acceptance criteria established by an operator.

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Figure 6. Kick Margin Risk, BOP SIL Optimiser and WPRA-H are part of Drilling PRA (DPRA) tool suite developed by UPSRM for complete probabilistic risk assessment of well drilling/intervention/PPA operations. Note human reliability analysis module, which represents true state-of-art capabilities within oil and gas industry for tackling upstream human and organisational factors!

VEGA R-12H WELLBORE QRA The objective of the study was to assess the impact of penetrating a shallow gas bearing formation on the wellbore leakage risk of Vega well R-12H. In particular was focus on potential leak paths external to the well casing program.

WELL RISK ANALYSIS IN GULLFAKS FIELD The objective of the study was to assess the total well internal and external leakage risk picture following new reservoir discovery: (i) Well blowout risk from reservoir when previously cased off. (ii) New tie-back casing design vs. old single string.

QRA FOR TRSCSSV CONCEPT SELECTION IN NORG UGS This study comprised a combined LCC/LCP and risk analysis made to evaluate 7 5/8” baseline and 9 5/8” big bore completions with single and dual TR-SCSSV solutions in order to identify the most safe and cost effective solution for infill drilling of additional UGS wells in the Norg field. The well cases considered: 7 5/8” with single 7” TRSCSSV w/insert WRSCSSV capability. 7 5/8” with dual „hot‟ 7” TRSCSSVs wo/insert WRSCSSV capability. 9 5/8” completion with single 7” TRSCSSV w/insert WRSCSSV capability. 9 5/8”completion with dual „hot‟ 9 5/8” TRSCSSVs wo/insert WRSCSSV capability

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GIMLE C-18AT2 WELL P&A RISK REVIEW The objective of the study was to assess the wellbore leakage risk that followed from impact of hole instability problems causing lost BHA with result causing a shallow P&A job.

GAS LIFT WELL RISK ANALYSIS FOR SARAWAK SHELL BERHAD The objective of the study was to perform an assessment of the gas lift release risk related to baseline well gas lift designs for unmanned platforms in the field. The project also examined aspects of risk reduction associated with gas lift gas in the annulus such as use of an Annulus Safety Check Valve (ASCV) located in the VR profile on the gas inlet side of the wellhead.

RISK ANALYSIS OF ANNULAR SAFETY VALVE VS. WELLHEAD CHECK VALVES FOR GAS LIFTED PLATFORM WELLS This study represented a risk assessment of gas lifted oil production wells on the Ekofisk 2/4X, Eldfisk Alpha and Bravo platforms. The wells were originally planned with packer type annular safety valves (ASV) as a barrier in the annulus flow path. However, an increased intervention frequency and operational problems/difficulties in pulling the completion strings prompted the search for alternative solutions. One alternative solution investigated was the use of check valves in the wellhead inlets to the tubing by the casing annulus valves. The risk assessment was performed in order to quantify whether this alternative well configuration gives an acceptable leakage/blowout risk level on the platforms or not.

RISK ANALYSIS OF NJORD WELL BARRIER FAILURE The objective of the risk analysis was to assess the effect of a small tubing to annulus leak located above the TR-SCSSV on the “leakage to the surroundings” probability for a gas injection well, and further to assess the effect of potential risk reducing measures.

RISK ANALYSIS OF TUNE WELL BARRIER FAILURE The objective of the project was to assess the effect of a known barrier failure (tubing to annulus communication below the SCSSV) on the well “leakage to the surroundings” probability, and further to assess the effect of potential risk reducing measures that can be implemented.

RISK ANALYSIS OF VARG A WELLHEAD PLATFORM GAS LIFT WELLS A risk assessment was carried out for an oil production well which was planned for conversion to continuous gas lift at the Varg A unmanned wellhead platform. The risk assessment was performed in order to investigate the risk level associated with the unsupported portion of the 24”-13 3/8”-10 3/4”x9 5/8” casing/cement program during gas lift operations, and to evaluate different alternative annulus barrier configurations for the well. The increased platform risk level related to lift gas releases in the wellhead area with respect to escalation effects (fire/explosion) was also evaluated in the study. An extension of the well risk analysis was later performed to investigate the feasibility of converting additional oil production wells on the Varg A platform to gas lift with an alternative annulus barrier configuration (without TR-SCASSV). A special factor considered was the limited remaining operational lifetime of the wells.

RISK EVALUATION OF BRAGE TUBING HANGERS The objective of this project was to alternative well and platform risk reducing measures in order to compensate for several leaking tubing hanger shoulder/neck seals at Brage.

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RISK ASSESSMENT OF JOSLYN SAGD WELLS A risk assessment was carried out concerning heavy oil wells at the Joslyn field. The objective of this project was to investigate the risk level associated with shallow SAGD operations following a previous steam chamber eruption.

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CORE R&D TEAM COMPETENCIES

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TYPICAL REFERENCES FOR THE CASE STUDIES 1. Rausand, M. and Høyland, A., System Reliability Theory – Models, Statistical Methods and

Applications, John Wiley & Sons, 2004 2. Rausand, M., Reliability of Safety-Critical Systems – Theory and Applications, John Wiley

& Sons, 2014 3. Rausand, M., Risk Assessment – Theory, Methods and Applications, John Wiley & Sons,

2011 4. The Petroleum Safety Authority Norway (PSA), http://www.ptil.no/ 5. PSA, The facilities regulations, http://www.ptil.no/facilities/category400.html#p48 6. PSA, The activities regulations, http://www.ptil.no/activities/category399.html# 7. The Bureau of Safety and Environmental Enforcement (BSEE), http://www.bsee.gov/ 8. BSEE, Code of Federal Regulations (CFR), http://www.ecfr.gov/ 9. The Norwegian Oil and Gas Association (NOGA), http://www.norskoljeoggass.no/ 10. International Association of Oil and Gas Producers (OGP), http://info.ogp.org.uk/ 11. Offshore Operators Committee (OOC), http://www.offshoreoperators.com/ 12. NORSOK, http://www.standards.no 13. NORSOK D-010, Well integrity in drilling and well operations, Rev. 4, June 2013 14. American Petroleum Institute (API), http://www.api.org/ 15. API RP 90, Annular Casing Pressure Management for Offshore Wells 16. API TR 10TR1, Cement Sheath Evaluation, 2008 17. NOGA's Well Integrity Forum (WIF) et al., An Introduction to Well Integrity, Rev 0, Dec.

2012 18. NOGA 070. Application of IEC 61508 and IEC 61511 in the Norwegian Petroleum

Industry, Stavanger, Norway. 2018 19. Strand, G-O., Well Safety. Risk Control in the Drilling Phase of Offshore Wells, Doctoral

thesis at Norwegian University of Science and Technology (NTNU), 2017:204 20. Strand, G.-O. (2018). On technologies for shale barrier evaluation in the North Sea

(OMAE2018-78309). ASME 2018 37th International Conference on Ocean, Offshore and Arctic Engineering. Madrid, Spain: ASME.

21. Vignes, B., Contribution to well integrity and increased focus on well barriers from a life cycle aspect, Doctoral thesis at University of Stavanger, 2011

22. Corneliussen, K., Well Safety. Risk Control in the Operational Phase of Offshore Wells, Doctoral thesis at Norwegian University of Science and Technology (NTNU), 2006:47

23. Holand, P., Offshore blowouts – causes and control, Gulf Publishing Company, 1997 24. Holand, P. and Awan H., Deepwater Kicks and BOP Performance, Unrestricted version.

ExproSoft report ES201252, Aug. 2012 25. PSA, Principles for management of barriers in the petroleum industry. Memo (in Norwegian). 26. SINTEF Offshore Blowout Database. http://www.sintef.no/home/Technology-and-

Society/Safety-Research/Projects/SINTEF-Offshore-Blowout-Database/ 27. Canada-Newfoundland and Labrador Offshore Petroleum Board (C-NLOPB),

http://www.cnlopb.nl.ca/ 28. Industry Recommended Practices (IRP) - Canada,

http://enform.ca/safety_resources/publications/Default.aspx?type=irp 29. Agência Nacional do Petróleo, Gás Natural e Biocombustíveis (ANP) – Brazil (in

Portuguese), http://www.anp.gov.br/